XASE:GSX Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2012

 

OR

 

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: 001-32369

 

GASCO ENERGY, INC.

 (Exact name of registrant as specified in its charter)

 

Nevada

 

98-0204105

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

8 Inverness Drive East, Suite 100, Englewood, Colorado 80112

 (Address of principal executive offices)           (Zip Code)

 

(303) 483-0044

(Registrant’s telephone number, including area code)

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company x

(Do not check if a smaller reporting company)

 

 

 

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

 

Number of common shares outstanding as of May 1, 2012:     169,499,981

 

 

 




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Cautionary Statement Regarding Forward-Looking Statements

 

Some of the information in this Quarterly Report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  All statements other than statements of historical facts included in this Quarterly Report, including, without limitation, statements regarding our future financial position, expectations with respect to our liquidity and capital resources, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.  These statements express, or are based on, our current expectations or forecasts about future events. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “should,” “would,” “could,” “expect,” “plan,” “intend,” “project,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or similar terminology.

 

Although any forward-looking statements contained in this Quarterly Report or otherwise expressed by us are, to the knowledge and in the judgment of our management, believed to be reasonable, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve and can be affected by inaccurate assumptions or by known and unknown risks and uncertainties (some of which are beyond our control) which may cause our actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Known material factors that could cause actual results to differ materially from expected results are discussed under Part I, Item 1A “Risk Factors” and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2011 and under Part II, Item 1A “Risk Factors” and elsewhere in this Quarterly Report. Additional risks or uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or future results.

 

The following are among the important factors that could cause future results to differ materially from any projected, forecasted, estimated or budgeted amounts that we have discussed in this Quarterly Report:

 

·                  our ability to maintain adequate cash flow from operations or to obtain adequate financing to fund our capital expenditures, meet working capital needs and grow our operations;

 

·                  our ability to secure adequate alternative financing to replace our revolving credit facility, and the terms of any such financing;

 

·                  overall demand for natural gas and oil in the United States and related fluctuations in natural gas and oil prices, upon which our operating results are directly dependent and which impact our ability to produce economically and may affect our borrowing base under any future credit agreement;

 

·                  our ability to successfully operate our business within the restrictions imposed on us by our debt agreements;

 

·      any requirement that we write down the carrying value of our oil and gas properties due to reductions in natural gas and oil prices or substantial downward adjustments to our estimated proved reserves;

 

·                  our ability to manage interest rate and commodity price exposure;

 

·                  any failure by the gatherer of our natural gas, which would negatively affect our ability to deliver our natural gas production for sale;

 

·                  marketing of oil and natural gas;

 

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·                  pipeline constraints;

 

·                  estimated reserves of natural gas and oil and underlying assumptions of such estimated reserves;

 

·                  operating hazards inherent to the natural gas and oil business and the drilling of wells;

 

·                  acquisition and development of oil and gas properties, and replacement of reserves;

 

·                  delays in obtaining drilling permits and the timing and amount of future production of natural gas and oil;

 

·                  technological changes;

 

·                  competition;

 

·                  scope and extent of our insurance coverage;

 

·                  title defects and deficiencies;

 

·                  federal and state regulatory or legislative developments, including with respect to environmental matters;

 

·                  shortages of supplies, equipment and personnel, and increases in operating costs and other expenses generally;

 

·                  general economic conditions in the United States and key international markets, including credit and capital market constraints; and

 

·                  our ability to remain in compliance with the NYSE Amex’s continued listing requirements.

 

Any of these factors could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us. We cannot assure you that our future results will meet our expectations. When you consider these forward-looking statements, you should keep in mind these factors.  All subsequent written and oral forward-looking statements made by us are expressly qualified in their entirety by these factors.  Readers are cautioned not to place undue reliance on our forward-looking statements, which speak only as of the date made. We assume no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

 

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GLOSSARY OF NATURAL GAS AND OIL TERMS

 

The following is a description of the meanings of some of the natural gas and oil industry terms that may be used in this Quarterly Report.

 

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

 

Bbl/d.  One Bbl per day.

 

Bcf.  Billion cubic feet of natural gas.

 

Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

Btu or British Thermal Unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

Completion.  The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry well, the reporting of abandonment to the appropriate agency.

 

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry well.  An exploratory or development well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil and gas in another reservoir.

 

Farm-in or farm-out.  An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage.  Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.  The assignor usually retains a royalty or reversionary interest in the lease.  The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

 

Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

 

MBbls.  Thousand barrels of crude oil or other liquid hydrocarbons.

 

Mcf.  Thousand cubic feet of natural gas.

 

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Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

MMBtu.  Million British Thermal Units.

 

MMcf.  Million cubic feet of natural gas.

 

MMcf/d.  One MMcf per day.

 

MMcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

Net acres or net wells.  The sum of the fractional working interest owned in gross acres or wells, as the case may be.

 

Present value of future net revenues or present value of discounted future net cash flows or present value or PV-10.  The pre-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10 is a non-GAAP financial measure.

 

Productive well.  A producing well is a well that is found to be mechanically capable of production.

 

Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

Proved area.  The part of a property to which proved reserves have been specifically attributed.

 

Proved developed oil and gas reserves.  Proved developed oil and gas reserves are reserves that can be expected to be recovered: through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved..

 

Proved reserves or proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

Proved properties.  Properties with proved reserves.

 

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Proved undeveloped reserves.  Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period and period-end costs and statutory tax rates (adjusted for permanent differences) and a 10% annual discount rate.

 

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

 

Unproved properties.  Properties with no proved reserves.

 

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

 

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ITEM I — FINANCIAL STATEMENTS

 

PART 1 — FINANCIAL INFORMATION

 

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

7,964,180

 

$

1,965,967

 

Accounts receivable

 

 

 

 

 

Joint interest billings

 

1,215,772

 

810,482

 

Revenue

 

1,034,514

 

1,483,382

 

Inventory

 

1,762,666

 

1,911,362

 

Notes receivable

 

1,692,321

 

500,000

 

Derivative instruments

 

1,062,071

 

865,358

 

Prepaid expenses

 

109,628

 

152,045

 

Total

 

14,841,152

 

7,688,596

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, at cost

 

 

 

 

 

Oil and gas properties (full cost method)

 

 

 

 

 

Proved properties

 

255,740,966

 

268,793,463

 

Unproved properties

 

36,987,331

 

36,938,162

 

Wells in progress

 

 

1,938,691

 

Facilities and equipment

 

1,542,286

 

1,502,921

 

Furniture, fixtures and other

 

60,592

 

167,737

 

Total

 

294,331,175

 

309,340,974

 

Less accumulated depletion, depreciation, amortization and impairment

 

(239,200,644

)

(234,132,806

)

Total

 

55,130,531

 

75,208,168

 

 

 

 

 

 

 

NONCURRENT ASSETS

 

 

 

 

 

Deposit

 

539,443

 

639,500

 

Deferred financing costs

 

1,051,259

 

1,117,972

 

Total

 

1,590,702

 

1,757,472

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

71,562,385

 

$

84,654,236

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable

 

$

1,544,180

 

$

2,649,772

 

Revenue payable

 

1,972,882

 

2,043,240

 

Advances from joint interest owners

 

96,733

 

98,512

 

Current portion of long-term debt

 

 

8,544,969

 

Accrued interest

 

1,207,617

 

586,556

 

Accrued expenses

 

226,770

 

355,224

 

Total

 

5,048,182

 

14,278,273

 

 

 

 

 

 

 

NONCURRENT LIABILITIES

 

 

 

 

 

5.5% Convertible Senior Notes due 2015, net of unamortized discount of $21,650,999 as of March 31, 2012 and $22,574,687 as of December 31, 2011

 

23,517,001

 

22,593,313

 

Deferred income from sale of assets

 

2,615,016

 

2,665,629

 

Asset retirement obligation

 

761,592

 

1,226,796

 

Derivative instruments

 

4,955,000

 

4,235,000

 

Total

 

31,848,609

 

30,720,738

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY

 

 

 

 

 

Series B Convertible Preferred stock - $0.001 par value; 20,000 shares authorized; zero shares outstanding

 

 

 

Series C Convertible Preferred stock - $0.001 par value; 2,000,000 shares authorized; 182,065 shares outstanding as of March 31, 2012 and 191,000 shares outstanding as of December 31, 2011

 

182

 

191

 

Common stock - $.0001 par value; 600,000,000 shares authorized; 169,573,681 shares issued and 169,499,981 outstanding as of March 31, 2012 and 168,084,515 shares issued and 168,010,815 outstanding as of December 31, 2011

 

16,957

 

16,808

 

Additional paid-in capital

 

262,412,659

 

262,344,286

 

Accumulated deficit

 

(227,633,909

)

(222,575,765

)

Less cost of treasury stock of 73,700 common shares

 

(130,295

)

(130,295

)

Total

 

34,665,594

 

39,655,225

 

 

 

 

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

71,562,385

 

$

84,654,236

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Gas

 

$

2,307,864

 

$

3,703,031

 

Oil

 

872,403

 

566,074

 

Total

 

3,180,267

 

4,269,105

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

Lease operating

 

1,697,171

 

1,341,432

 

Transportation and processing

 

656,972

 

801,715

 

Depletion, depreciation, amortization and accretion

 

850,027

 

849,824

 

Impairment

 

4,300,000

 

 

Gain on sale of assets, net

 

(9,170

)

 

General and administrative

 

1,404,982

 

1,126,163

 

Total

 

8,899,982

 

4,119,134

 

 

 

 

 

 

 

OPERATING (LOSS) INCOME

 

(5,719,715

)

149,971

 

 

 

 

 

 

 

OTHER (EXPENSE) INCOME

 

 

 

 

 

Interest expense

 

(1,728,769

)

(1,863,895

)

Gain on sale of assets

 

2,567,574

 

 

Derivative (losses) gains

 

(236,867

)

63,953

 

Amortization of deferred income from sale of assets

 

50,613

 

50,613

 

Interest income

 

9,020

 

6,881

 

Total

 

661,571

 

(1,742,448

)

 

 

 

 

 

 

NET LOSS

 

$

(5,058,144

)

$

(1,592,477

)

 

 

 

 

 

 

NET LOSS PER COMMON SHARE — BASIC AND DILUTED

 

$

(0.03

)

$

(0.01

)

 

 

 

 

 

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC AND DILUTED

 

168,213,801

 

125,126,533

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net loss

 

$

(5,058,144

)

$

(1,592,477

)

Adjustment to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation, amortization, accretion and impairment expense

 

5,150,027

 

849,824

 

Stock-based compensation

 

60,005

 

169,900

 

Change in fair value of derivative instruments

 

523,287

 

342,047

 

Gain on sale of assets

 

(2,567,574

)

 

Amortization of debt discount, deferred expenses and other

 

939,788

 

736,946

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

43,577

 

79,178

 

Inventory

 

148,696

 

676

 

Prepaid expenses

 

42,417

 

36,566

 

Accounts payable

 

(325,592

)

(703,450

)

Revenue payable

 

(70,357

)

423,929

 

Accrued interest

 

621,061

 

1,007,596

 

Accrued expenses

 

854

 

(432,946

)

Net cash provided by operating activities

 

(491,955

)

917,789

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid for furniture, fixtures and other

 

 

(892

)

Cash paid for acquisitions, development and exploration

 

(2,942,141

)

(1,957,569

)

Proceeds from sale of assets

 

18,000,000

 

 

Decrease in advances from joint interest owners

 

(1,779

)

(791,349

)

Net cash provided by (used in) investing activities

 

15,056,080

 

(2,749,810

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings under line of credit

 

2,000,000

 

1,000,000

 

Repayment of borrowings

 

(10,544,969

)

 

Cash paid for deposit

 

(20,943

)

 

Cash paid for debt issuance costs

 

 

(65,000

)

Net cash (used in) provided by financing activities

 

(8,565,912

)

935,000

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

5,998,213

 

(897,021

)

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS:

 

 

 

 

 

BEGINNING OF PERIOD

 

1,965,967

 

1,994,542

 

END OF PERIOD

 

$

7,964,180

 

$

1,097,521

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

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GASCO ENERGY, INC.

NOTES TO UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

THREE MONTHS ENDED MARCH 31, 2012 AND 2011

 

NOTE 1 — ORGANIZATION

 

Gasco Energy, Inc. (“Gasco,” the “Company,” “we,” “our” or “us”) is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. The Company’s principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in these areas. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. The Company is currently focusing its operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

 

The unaudited condensed consolidated financial statements included herein were prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”) applicable to interim financial statements and with the instructions to Form 10-Q and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements.  The accompanying unaudited condensed consolidated financial statements reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position of the Company for the interim periods presented.  Such financial statements conform to the presentation reflected in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 10-K”) filed with the SEC on March 28, 2012. The current interim period financial statements included herein should be read in conjunction with the financial statements and accompanying notes, including Note 2 — Significant Accounting Policies, included in the Company’s 2011 10-K.

 

The results of operations for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

 

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements include Gasco and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated.

 

Oil and Gas Properties

 

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $8,637 and $48,573 of internal costs during the three months ended March 31, 2012 and 2011, respectively. Additionally, the Company capitalized stock compensation expense related to its consultants as further described in Note 7 — Stock-Based Compensation, herein. Costs associated with production and general corporate activities are expensed in the period incurred. The Company charges a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and,

 

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therefore, net income (loss) attributable to the outside working interest owners from such marketing activities of $5,513 and $(37,994) was recorded as an adjustment to proved properties during the three months ended March 31, 2012 and 2011, respectively. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. Please see Note 3 — Asset Sales, herein.

 

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include: (i) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion; (ii) estimated future development costs to be incurred in developing proved reserves; and (iii) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs.

 

Total well costs are transferred to the depletable pool even when multiple targeted zones have not been fully evaluated. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Estimated reserve quantities are affected by changes in commodity prices and actual well performance.

 

Under the full cost method of accounting, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average first-day-of-the-month oil and gas prices during the 12-month period ended March 31, 2012 to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. As of March 31, 2012, our full cost pool exceeded the ceiling limitation based on the average, first-day-of-the-month oil and gas prices of $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012. Therefore, impairment expense of $4,300,000 was recorded during the quarter ended March 31, 2012.

 

Wells in Progress

 

Wells in progress at December 31, 2011, represent the costs associated with the drilling of two wells in the Riverbend area of Utah. Since the wells had not been completed as of December 31, 2011, they were classified as wells in progress and were withheld from the depletion calculation and the ceiling test. The costs for these wells were transferred into proved property during January 2012 when the wells reached total depth and were cased and became subject to depletion and the ceiling test calculation in future periods.

 

Facilities and Equipment

 

The Company’s other oil and gas equipment is depreciated using the straight-line method over an estimated useful life of five to ten years. The rental of the equipment owned by the Company is charged to the wells that

 

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are operated by the Company and, therefore, the net expense attributable to the outside working interest owners from the equipment rental was recorded as an adjustment to proved properties in the amount of $15,834 and $33,165 during the three months ended March 31, 2012 and 2011, respectively.

 

Commodity Derivatives

 

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all commodity derivative instruments at fair value within the accompanying unaudited condensed consolidated balance sheets. The Company’s management has decided not to use hedge accounting under the accounting guidance for its commodity derivatives and therefore, the changes in fair value are recognized currently in earnings. See Note 5 — Derivatives, herein.

 

Warrants

 

On June 15, 2011, the Company issued warrants (“June Warrants”) to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued warrants (“August Warrants” and collectively with the June Warrants, the “Warrants”) to purchase 11,500,000 shares of common stock. The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share; however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction.  If the Company makes a distribution of its assets to all of its stockholders, holders of the Warrants may be entitled to participate. In the event of a Fundamental Transaction (as defined in the Warrants), at the election of a holder of a Warrant, the Company may be required to purchase the holder’s Warrant for cash in an amount equal to the value of the remaining unexercised portion of the Warrant.  As a result, the Warrants are accounted for as a liability on the Company’s consolidated balance sheet with changes in their fair value reported in earnings. The June Warrants and the August Warrants were recorded at their fair values of $1,850,625 and $2,185,000, respectively, at the issuance dates. Subject to certain exceptions, if the average of the daily volume weighted-average price of a share of common stock for some period of time equals or exceeds 200% of the initial exercise price of the Warrants, and if at the time of such measurement the Equity Conditions (as defined in the Warrants) are satisfied, then the Company may, subject to certain conditions, require the holders of the Warrants to exercise.

 

Asset Retirement Obligation

 

The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and gathering system using the units-of-production method. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability is allocated to operating expense using a systematic and rational method.

 

The information below reconciles the value of the asset retirement obligation for the periods presented.

 

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Three Months Ended
March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Balance beginning of period

 

$

1,226,796

 

$

1,119,561

 

Liabilities incurred

 

 

 

Property dispositions

 

(493,178

)

 

Accretion expense

 

27,974

 

25,531

 

Balance end of period

 

$

761,592

 

$

1,145,092

 

 

See Note 3 — Asset Sales, herein, for discussion of property dispositions.

 

Revenue Recognition

 

The Company records revenues from the sales of natural gas and crude oil when delivery to the customer has occurred, title has transferred and collectability is reasonably assured. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.

 

The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves.

 

Off Balance Sheet Arrangements

 

From time to time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

 

Computation of Net Income (Loss) Per Share

 

Basic net income (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  Potentially dilutive securities for the diluted earnings per share calculation consist of (i) unvested shares of restricted common stock, (ii) in-the-money outstanding options and warrants to purchase the Company’s common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the

 

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Company’s common stock, and (iv) the Company’s outstanding 5.5% Convertible Senior Notes due 2015 (“2015 Notes”) which are convertible into shares of Preferred Stock and common stock.

 

The treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares that could have been repurchased by the Company with the proceeds from the exercise of the options (which repurchases were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock and shares into which the 2015 Notes and Preferred Stock are convertible.

 

Net income (loss) per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the Preferred Stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, earnings are allocated to both common stock shares and the Preferred Stock common stock equivalent shares based on their respective weighted-average shares outstanding for the period. Losses are not allocated to Preferred Stock shares and basic and diluted net loss per share for the quarters ended March 31, 2012 and 2011were the same.

 

The following shares were excluded from the computation of diluted loss per common share as they did not have a dilutive effect.

 

 

 

For the Three Months
Ended March 31,

 

 

 

2012

 

2011

 

Shares related to:

 

 

 

 

 

Convertible Senior Notes

 

75,280,000

 

75,380,000

 

Preferred stock

 

30,344,173

 

31,833,340

 

Common stock options

 

8,839,468

 

10,797,143

 

Warrants

 

30,250,000

 

 

Unvested restricted stock

 

182,100

 

180,700

 

 

Use of Estimates

 

The preparation of the financial statements for the Company in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

 

The Company’s financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, timing and costs associated with its retirement obligations, estimates of the fair value of derivative instruments, estimates used in stock-based compensation calculations and impairments to unproved property and to proved oil and gas properties.

 

Recently Issued Accounting Pronouncements

 

Effective January 1, 2012, the Company adopted Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards.” The adoption of ASU 2011-04 did not have a significant impact on the Company’s consolidated financial position or results of operations.

 

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NOTE 3 — ASSET SALES

 

Uinta Basin Joint Venture

 

On March 22, 2012, the Company closed a previously announced transaction (the “Uinta Basin Transaction”) whereby, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated February 23, 2012, between the Company’s wholly owned subsidiary, Gasco Production Company, and Wapiti Oil & Gas II, L.L.C. (“Wapiti”), and a Closing Agreement (the “Closing Agreement”) dated March 22, 2012 relating to the Purchase Agreement, the Company (i) sold to Wapiti an undivided 50% of its interest in certain of its Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti and (ii) transferred to Wapiti an undivided 50% of its interest in its Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets. The promissory note receivable will bear interest at 5% and is due on or before May 21, 2012, based on certain circumstances as described in the promissory note agreement.

 

As a part of the Uinta Basin Transaction, Gasco Production Company entered into a Development Agreement (the “Development Agreement”) with Wapiti, which includes terms and conditions of a drilling program agreed to by the parties.

 

Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on our behalf, and we have agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million; provided that, if on February 23, 2013, the five-year New York Mercantile Exchange (“NYMEX”) natural gas strip pricing is at least $5.00/MMBtu, the drilling and completion program will be expanded by $6.25 million to $43.75 million with Wapiti paying for $5.0 million of the additional costs.

 

The drilling and completion program will continue until Wapiti’s funding commitment has been fully expended or for a shorter period, if the Operating Committee (as defined below) votes to cease the drilling program after Wapiti has expended $10.0 million on drilling and completion costs related to the program wells (the “Drilling Term”).  The Company may suspend the drilling program, including the expenditure of Wapiti’s funding commitment, for up to six months if certain governmental environmental studies have not been completed by the time that $23.6 million of Wapiti’s funding commitment has been expended.

 

With respect to wells drilled pursuant to the drilling program, the net revenue interest attributable to such wells from the closing through the time when the cumulative proceeds received by Wapiti from such wells equals the amount of costs actually paid by Wapiti in respect of such wells and the drilling program (such time, “Payout”), will be allocated 32.5% to the Company and 67.5% to Wapiti. After Payout, the net revenue interest will be allocated in proportion to the actual net revenue interests of the parties in such wells.  With respect to each well drilled pursuant to the drilling program, (i) all drilling and completion costs will be borne (a) during the Drilling Term, 20% by the Company and 80% by Wapiti, (b) after the Drilling Term but before Payout, 32.5% by the Company and 67.5% by Wapiti, and (c) after Payout, in proportion to the actual working interests of the parties in such wells, and (ii) all other working interest costs will be borne (x) before Payout, 32.5% by the Company and 67.5% by Wapiti, and (y) after Payout, in proportion to the actual working interests of the parties in such wells.

 

Subject to the terms of the Development Agreement, the Company will manage the operations contemplated by the drilling program.  Except for the subject assets that are already subject to joint operating agreements with third parties, the operation of (i) a portion of the subject assets will be subject to an agreed upon joint operating agreement (a “JOA”), which names Gasco Production Company as operator of record, and (ii) the remaining portion of the subject assets will be subject to an agreed upon JOA, which names Wapiti as operator of record. 

 

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Gasco Production Company and Wapiti also entered into a contract operating agreement naming Gasco Production Company as contract operator with respect to the portion of the subject assets for which Wapiti is named as operator of record.  The Company and Wapiti have formed an Operating Committee (the “Operating Committee”) to oversee generally the drilling program and operations in the project area and to approve certain matters specified in the Development Agreement. The Operating Committee will consist of two members from each of us and Wapiti, with the members appointed by each party having an aggregate 50% vote.

 

The Development Agreement also contains transfer restrictions on each of our and Wapiti’s ability to transfer its respective interests in the subject assets. The Development Agreement also contains a customary area of mutual interest provision covering the Project Area. With certain limited exceptions, the Development Agreement will remain in effect during the Drilling Term; however, after the six-month anniversary of the end of the Drilling Term, the Development Agreement may be terminated by either us or Wapiti upon six months’ advance notice.

 

The foregoing description of the Uinta Basin Transaction, including the Purchase Agreement, the Closing Agreement and the Development Agreement, do not purport to be complete and are qualified in their entirety by reference to the full text of the Purchase Agreement, the Closing Agreement and the Development Agreement, which are attached as exhibits to our Current Report on Form 8-K filed on March 28, 2012.

 

We used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under our credit facility, and we will use the remaining proceeds for capital expenditures, working capital, acquisitions of oil and natural gas properties and other general corporate purposes.

 

The sale of the proved property in the Uinta Basin Transaction was recorded by recognizing a gain of $2,567,574 rather than recording a credit to the full cost pool for the proceeds because this method would significantly alter the relationship between capitalized costs and the proved reserves attributable to the cost center.

 

No adjustments were made to the carrying value of the unproved properties upon the closing of the Uinta Basin Transaction. Rather as the wells are drilled, the cost basis of the unproved property associated with each well drilled will be reclassified from unproved property to the full cost pool to be depleted and included in the ceiling test. The cost basis will be determined based on a per acre valuation multiplied by the number of acres for each drilling location.

 

The following unaudited pro forma information is presented as if the Uinta Basin Transaction had an effective date of January 1, 2011, and is not necessarily indicative of either future results of operations or results that might have been achieved had the transaction been consummated as of January 1, 2011.

 

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Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Revenue as reported

 

$

3,180,267

 

$

4,269,105

 

Less: revenue from the Uinta Basin Transaction

 

(1,206,145

)

(1,508,084

)

Pro forma revenue

 

$

1,974,122

 

$

2,761,021

 

 

 

 

 

 

 

Net loss as reported

 

$

(5,058,144

)

$

(1,592,477

)

Less: operating loss resulting from the Uinta Basin Transaction

 

(2,390,235

)

(507,804

)

Pro forma net loss

 

(2,667,909

)

(1,084,673

)

 

 

 

 

 

 

Net loss per share — basic and diluted as reported

 

$

(0.03

)

$

(0.01

)

Less net loss per share - from the Uinta Basin Transaction

 

(0.01

)

0.00

 

Pro forma net loss per share — basic and diluted

 

$

(0.02

)

$

(0.01

)

 

Prospect Fee

 

During January 2012, the Company entered into an arrangement with an exploration and production company which operates in California, pursuant to which the Company received a $750,000 prospect fee related to certain of its California acreage. The fee reimbursed costs that the Company has invested in the area and provides it with a potential carried interest of 20% in two wells to be drilled on the acreage. The proceeds were recorded as a credit to unproved properties during the three months ended March 31, 2012.

 

NOTE 4 - CONVERTIBLE SENIOR NOTES

 

As of March 31, 2012 and December 31, 2011, the Company had $45,168,000 aggregate principal amount of 2015 Notes outstanding.

 

2015 Notes

 

The 2015 Notes are governed by an indenture, dated as of June 25, 2010, by and between the Company and Wells Fargo Bank, National Association, as trustee (the “2015 Indenture”). The 2015 Notes were issued on June 25, 2010 (the “Issue Date”) pursuant to the exemption from the registration requirements of the Securities Act of 1933 (the “Securities Act”), provided by Section 4(2) and Regulation D thereunder. The 2015 Notes have a maturity date of October 5, 2015.

 

The 2015 Notes bear interest at a rate of 5.50% per annum, and such interest is payable in cash semi-annually in arrears on April 5th and October 5th of each year.

 

The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the 2015 Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the

 

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outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.

 

The Company may redeem the 2015 Notes in whole or in part for cash at any time at a redemption price equal to 100% of the principal amount of the 2015 Notes plus any accrued and unpaid interest and liquidated damages, if any, on the 2015 Notes redeemed to but not including the redemption date, if the closing price of the Company’s common stock equals or exceeds 150% of the conversion price for at least 20 trading days within the consecutive 30 trading day period ending on the trading day before the redemption date and all of the Equity Conditions (as defined in the 2015 Indenture) are satisfied (or waived in writing by the holders of a majority in aggregate principal amount of the 2015 Notes then outstanding). If a holder elects to convert its 2015 Notes in connection with such a provisional redemption by the Company, the Company will make an additional payment equal to the total value of the aggregate amount of the interest otherwise payable on the 2015 Notes to be calculated from the last day through which interest was paid on the 2015 Notes through and including the third anniversary of the Issue Date and discounted to the present value of such payment; provided, however, that at the Company’s option, in lieu of such discounted cash payment, the Company may deliver shares of Preferred Stock having a value equal to such discounted cash payment. The value of each share of Preferred Stock to be delivered shall be deemed equal to the product of (i) the average closing price per share of common stock over the ten trading day period ending on the trading day before the redemption date, and (ii) the number of whole shares of common stock into which each share of Preferred Stock is then convertible (without giving effect to any limitations on conversion in the Certificate of Designations of the Preferred Stock) (subject to certain conditions).

 

Upon a change of control (as defined in the 2015 Indenture), each holder of 2015 Notes may require the Company to repurchase some or all of its 2015 Notes at a repurchase price equal to 100% of the aggregate principal amount of the 2015 Notes to be repurchased plus accrued and unpaid interest and liquidated damages, if any, to but not including the date of purchase, plus, in certain circumstances, a make whole premium. The Company may pay the change of control purchase price and/or the make whole premium in cash or shares of Preferred Stock at the Company’s option. In addition, in the case of the make whole premium, at the Company’s option, the Company may pay such premium in the same form of consideration used to pay for the shares of common stock in connection with the transaction constituting the change of control.

 

The 2015 Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guarantee the 2015 Notes, requiring it to list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE Amex or any other U.S. national or regional securities exchange on which the common stock is then listed, and requiring it to use reasonable best efforts to obtain stockholder approval for the issuance of shares of common stock upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes.

 

The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness, rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.

 

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The debt discount that was recognized in connection with the 2015 Notes is being accreted to interest expense under the effective interest method at a rate of 26.3%.

 

NOTE 5 — DERIVATIVES

 

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. As of March 31, 2012 and December 31, 2011, natural gas derivative instruments consisted of one costless collar agreement for production from January 1, 2012 through December 31, 2012. These natural gas derivative instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. The Company’s costless collar contains a fixed floor price (purchase put) and ceiling price (written call). The Company receives the difference between the published index price and the floor price if the index price is below the floor price. The Company pays the difference between the ceiling price and the index price only if the index price is above the ceiling price. If the index price is between the ceiling and the floor prices, no amounts are paid or received.

 

On June 15, 2011, the Company issued the June Warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued the August Warrants to purchase 11,500,000 shares of common stock. The Warrants have an initial exercise price of $0.35 per share (subject to adjustment) and sixty-month term. The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments.

 

The following table details the fair value of the derivatives recorded in the consolidated balance sheets:

 

 

 

Location on
Consolidated

 

Fair Value at

 

 

 

Balance Sheets

 

March 31, 2012

 

December 31, 2011

 

 

 

 

 

 

 

 

 

Natural gas derivative contract

 

Current assets

 

$

1,062,071

 

$

865,358

 

Warrant derivative

 

Noncurrent liabilities

 

4,955,000

 

4,235,000

 

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2012 and 2011.

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Realized gains on commodity instruments

 

$

286,420

 

$

406,000

 

Change in fair value of commodity instruments

 

196,713

 

(342,047

)

Change in fair value of warrant derivative

 

(720,000

)

 

 

 

 

 

 

 

Total realized and unrealized gains (losses) recorded

 

$

(236,867

)

$

63,953

 

 

These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations as derivative gains and losses.

 

The Company’s costless collar agreement as of March 31, 2012 is summarized in the table below:

 

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Agreement
Type

 

Remaining
Term

 

Quantity

 

Index
Price (a)

 

Call Price
Counterparty
buyer

 

Put Price
Gasco buyer

Costless collar

 

4/12 – 12/12

 

2,000 MMBtu/day

 

NW Rockies

 

$4.25/MMBtu

 

$5.12/MMBtu

 


(a)                                 Northwest Pipeline Rocky Mountains — Inside FERC first-of-month index price.

 

NOTE 6 — GAS PROCESSING AGREEMENT

 

On September 21, 2011, the Company entered into a Gas Processing Agreement (the “Chipeta Processing Agreement”) with Chipeta Processing LLC (“Chipeta”) pursuant to which the Company dedicated certain of its natural gas production from its acreage in Utah to Chipeta for processing, and Chipeta agreed to process all natural gas production from such assets through facilities and related equipment that Chipeta owns or will construct on or before December 31, 2012.

 

The primary term of the Chipeta Processing Agreement is ten years, beginning after the in-service date of a 300 MMcf/d cryogenic processing facility to be built by Chipeta. The primary term will be extended for one year terms unless terminated by either party giving 180 days’ notice prior to the expiration of the then-current term.  If by December 31, 2012, among other conditions, (i) Chipeta has not completed its construction obligation and (ii) Questar Pipeline Company has not completed and received necessary regulatory approvals for the conversion of certain of its pipelines and facilities from a dry line to a wet line, the obligations of the Company and Chipeta under the Chipeta Processing Agreement shall be void.

 

Pursuant to the Chipeta Processing Agreement, the Company reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  The Company agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis.  The Company may also be required to make periodic deficiency payments to Chipeta for any shortfalls from the specified minimum volume commitments.

 

Historically, the Company’s natural gas production has been gathered and processed by Monarch Natural Gas, LLC, a Delaware limited liability company (“Monarch”) pursuant to the Gas Gathering and Processing Agreement effective March 1, 2010 between Monarch and the Company (the “Monarch Processing Agreement”).  In connection with the Chipeta Processing Agreement, on September 20, 2011, the Company entered into a Letter Agreement to Amend the Monarch Processing Agreement (the “Monarch Amendment”).

 

On March 22, 2012, we entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch which amends, restates and replaces the Monarch Processing Agreement and Monarch Amendment described above.  Under the Amended and Restated Monarch Agreement, Monarch agreed to, among other things, (a) release and waive its rights to process the first 50,000 MMBtu/day of our gas delivered to Monarch’s gathering system pursuant to the Amended and Restated Monarch Agreement (the “Excluded Production”) and (b) retain all processing rights for all gas volumes produced from certain of our reserves in excess of the Excluded Production.  The Excluded Production may be reduced if we fail to meet certain drilling investment targets.  The term of the Amended and Restated Monarch Agreement extends through February 28, 2025, and, for wells that are already connected to Monarch’s gathering system on February 28, 2025, for so long as our gas can be produced in commercial quantities from such wells.

 

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NOTE 7 — STOCK-BASED COMPENSATION

 

The Company has outstanding common stock options, stock appreciation rights (“SARs”) and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period. The expense recognized over the service period includes an estimate of the awards that will be forfeited.  Gasco assumes no forfeitures for employee awards based on the Company’s historical forfeiture experience.  The Company accounts for its SARs as liability based awards and accordingly the Company recognizes the fair value of the vested SARs each reporting period. The fair value of stock options and SARs is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair value of the stock on the date of grant.

 

The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the three months ended March 31, 2012 and 2011, the Company recognized stock-based compensation as follows:

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Employee compensation

 

$

63,960

 

$

169,032

 

Consultant compensation (reduction in compensation)

 

(3,755

)

1,736

 

Total stock-based compensation

 

60,205

 

170,768

 

Less: consultant compensation expense (reduction in expense) capitalized as proved property

 

200

 

868

 

Stock-based compensation expense

 

$

60,005

 

$

169,900

 

 

Stock Options

 

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2012 through March 31, 2012:

 

 

 

Shares Underlying
Stock Options

 

Weighted-Average
Exercise Price

 

Outstanding at January 1, 2012

 

8,182,647

 

$

1.63

 

Granted

 

836,485

 

$

0.29

 

Exercised

 

 

 

Forfeited

 

 

 

Cancelled

 

(179,664

)

$

0.74

 

Outstanding at March 31, 2012

 

8,839,468

 

$

1.31

 

Exercisable at March 31, 2012

 

6,888,140

 

$

1.59

 

 

During the first three months of 2012, the Company granted 836,485 options to purchase common stock with exercise prices ranging from $0.21 to $0.30 per share. These options have a two-year vesting period and expire five years from the grant date. The total grant date fair value of the options granted during the first quarter of 2012 was $153,507.

 

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The following table summarizes information related to outstanding and vested options as of March 31, 2012:

 

 

 

Outstanding Options

 

Vested Options

 

Number of Shares

 

8,839,468

 

6,888,140

 

Weighted-Average Remaining Contractual Life

 

2.8 years

 

2.6 years

 

Weighted-Average Exercise Price

 

$

1.31

 

$

1.59

 

Aggregate Intrinsic Value

 

$

63,424

 

$

1,850

 

 

The aggregate intrinsic value in the table above represents the total pretax intrinsic value. As of March 31, 2012, the fair value of the Company’s stock was $0.26 which would have been received by the option holders had they exercised their options as of that date.

 

The Company settles employee stock option exercises with newly issued common shares.

 

As of March 31, 2012, there is $277,762 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 1.95 years.

 

Restricted Stock

 

The following table summarizes the restricted stock activity from January 1, 2012 through March 31, 2012:

 

 

 

Restricted
Stock

 

Weighted-Average
Grant Date
Fair Value

 

Outstanding at January 1, 2012

 

184,500

 

$

0.36

 

Granted

 

 

 

Vested

 

(2,400

)

$

0.22

 

Forfeited

 

 

 

Outstanding at March 31, 2012

 

182,100

 

$

0.36

 

 

As of March 31, 2012, there is $56,703 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a period of 2.35 years.

 

SARs

 

Effective October 1, 2011, the Company’s non-employee directors agreed to reduce their monthly compensation and in exchange, on October 5, 2011, the Company granted SARs related to a total of 500,000 shares of the Company’s common stock to these directors. As of December 31, 2011, the SARs were recorded as a liability of $10,924 in the accompanying unaudited condensed consolidated financial statements. The SARs provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) the fair market value of one share of common stock on the date of exercise, over (ii) $0.25, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised (“Appreciation Amount”). The SARs vested on January 31, 2012 and were automatically exercised on February 1, 2012. The fair market value of the common stock on the date of exercise was below $0.25 per share and therefore the Appreciation Amount was zero and

 

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no cash payment was made.

 

Effective February 28, 2012, the Company granted another stock SARs award (“February SARs”) related to a total of 1,000,000 shares of our common stock to these directors.  The February SARs provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) (A) the fair market value of one share of common stock on the date of exercise or (B) $2.00, whichever is greater, over (ii) $0.30, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised. The February SARs vest on January 31, 2013 and will be automatically exercised on February 1, 2013.

 

NOTE 8 — CREDIT FACILITY

 

The Company’s $250 million revolving credit facility (“Credit Facility”) has been available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. As of December 31, 2011, the borrowing base was $13 million. On March 22, 2012, the Company repaid $10,544,969 which represented all borrowings outstanding under the Credit Facility.

 

On March 22, 2012, in connection with the consummation of the Uinta Basin Transaction discussed in Note 3 — Asset Sales, herein, the Company entered into a Twelfth Amendment (the “Twelfth Amendment”) to its Credit Facility. The Twelfth Amendment, among other things, (i) extended the maturity of the Credit Facility to June 29, 2012, (ii) permitted the consummation of the  Uinta Basin Transaction discussed in Note 3 — Asset Sales, herein, (iii) reduced the availability of aggregate commitments under the Credit Facility to $25,195.25, and (iv) addressed letter of credit availability through maturity.

 

The Company is discussing alternative borrowing arrangements with other lenders and while the Company currently believes that it will be able to find a replacement lender, there can be no assurance that it will be able to obtain adequate alternative financing on acceptable terms or at all. For example, the Company’s recent results of operations and volatility in oil and gas prices as well as in the domestic credit and capital markets generally may negatively affect the availability and terms of financing. If the Company is able to secure an alternative borrowing arrangement, it expects that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of the Credit Facility.  If the Company is unable to secure an alternative borrowing arrangement, it will lose a primary source of liquidity and will be required to fund its business and operations going forward with cash flow from operations and cash on hand.  There is no guarantee that the Company will be able to do so, in which case it may have to significantly reduce its spending and may be unable to execute its existing short-term and long-term business plan, and its liquidity and results of operations may be materially adversely affected.

 

Interest on borrowings under the Credit Facility accrue at variable interest rates at either a Eurodollar rate or an alternate base rate (“ABR”). The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBOR for a one-month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the lenders could require the Company to use the non-elected basis in the event that the elected basis did not adequately and fairly reflect the cost of making such loans.

 

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The Credit Facility requires the Company to comply with financial covenants that require it to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Any failure to comply with any material provision or covenant of the Credit Facility will result in a default which would, absent a waiver or amendment, will require immediate repayment of outstanding indebtedness under the Credit Facility.  Additionally, should the Company’s obligation to repay indebtedness under the Credit Facility have been accelerated, the Company would have been in default under the indenture governing the 2015 Notes, which would have required repayment of the outstanding principal, interest and liquidated damages, if any, on the 2015 Notes.

 

As of March 31, 2012, the Company’s current ratio was 2.7:1.0 and its senior debt to EBITDAX ratio is 0.0:1.0, and the Company was in compliance with each of the covenants contained in the Credit Facility.

 

NOTE 9 — FAIR VALUE MEASUREMENTS

 

The authoritative guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

 

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

 

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

 

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations.

 

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011 by level within the fair value hierarchy:

 

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Fair Value Measurements Using

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

March 31, 2012

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

1,062,071

 

$

 

$

1,062,071

 

Liabilities:

 

 

 

 

 

 

 

 

 

Warrant derivatives

 

$

 

$

 

$

4,955,000

 

$

4,955,000

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

 

$

856,358

 

$

 

$

856,358

 

Liabilities:

 

 

 

 

 

 

 

 

 

Warrant derivatives

 

$

 

$

 

$

4,235,000

 

$

4,235,000

 

 

As of March 31, 2012, the Company’s commodity derivative financial instruments consist of one costless collar agreement. The fair value of the collar agreement is determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivative and is, therefore, considered Level 2 in the fair value hierarchy. The Company determines the fair value of this contract under the income valuation technique using an option pricing model. The valuation model requires a variety of inputs, including contractual terms, projected gas market prices, discount rate and credit risk adjustments, as appropriate. The Company believes it has obtained the most accurate information available for the types of derivative contracts it holds. The counterparty to all of the Company’s commodity derivative financial instruments is the Administrative Agent under the Credit Facility. See Note 8 — Credit Facility, herein.

 

As of March 31, 2012, the Company’s warrant derivative financial instrument is comprised of the Warrants issued by the Company to purchase 30,250,000 shares of common stock. The Warrants are valued using a binomial lattice-based valuation model and are classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique is utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that are necessary to measure the fair value of these instruments. The valuation policies are determined by the CAO and are approved by the CEO. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the CAO and the CEO update the inputs used in the fair value calculations and internally review the changes from period to period for reasonableness. The Company uses data from its peers as well as from external sources in the determination of the volatility and risk free interest rates used in the fair value calculations. A sensitivity analysis is performed as well to determine the impact of the inputs on the ending fair value estimate. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument due to both internal and external market factors. In addition, option-based techniques are highly sensitive to volatility assumptions, particularly since the trading price of the Company’s common stock has a high-historical volatility. With all other factors remaining constant as of March 31, 2012:

 

(i)             the warrant derivative liability would decrease by approximately $2.2 million for a $0.10 decrease in the trading price of our common stock and would increase by approximately $2.6 million for a $0.10 increase in the trading price of our common stock; and

 

(ii)          the warrant derivative liability would increase by approximately $490,000 by a 10% increase in the volatility rate and would decrease by approximately $417,000 by a decrease in the volatility rate of 10%.

 

A summary of the Warrants issued by the Company is as follows:

 

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Number of
Warrants

 

Exercise
Price

 

Weighted
Average
Remaining
Contractual Life

 

Warrants outstanding as of 12/31/11

 

30,250,000

 

$

0.35

 

54.1 months

 

Warrants issued

 

 

 

 

Warrants outstanding as of 3/31/12

 

30,250,000

 

$

0.35

 

51.0 months

 

 

The significant assumptions used in the valuation of the warrant derivative liability are as follows:

 

Exercise price

 

$0.35 per share

 

Volatility

 

95.5%

 

Term of Warrants

 

60 months

 

Risk-free interest rate

 

1% - 2%

 

 

The following table sets forth a reconciliation of changes in the fair value of financial liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2012. There were no Level 3 liabilities as of March 31, 2011:

 

 

 

Warrant
Derivative

 

Balance as of January 1, 2012

 

$

(4,235,000

)

Total gains (realized or unrealized):

 

 

 

Included in earnings

 

(720,000

)

Included in other comprehensive income

 

 

Issuances

 

 

Settlements

 

 

Transfers in and out of Level 3

 

 

Balance as of March 31, 2012

 

$

(4,955,000

)

 

 

 

 

Change in unrealized gains included in earnings relating to instruments still held as of March 31, 2012

 

$

(720,000

)

 

The carrying amounts of cash and cash equivalents, accounts receivable, note receivable, accounts payable and accrued liabilities approximate fair values because of the short-term maturities and or liquid nature of these assets and liabilities. The estimated fair value of the 2015 Notes of $39,597,566 and $31,443,000 as of March 31, 2012 and December 31, 2011, respectively, was determined using a discounted cash flow and option pricing model.

 

NOTE 10 - STATEMENTS OF CASH FLOWS

 

During the three months ended March 31, 2012, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Stock-based compensation expense of $200 capitalized as proved property.

 

·      Sale of property in exchange for a $1,192,321 promissory note receivable.

 

·      Settlement of a $121,000 liability with a prepaid deposit.

 

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·      Conversion of 8,935 shares of Preferred Stock into 1,489,166 shares of common stock.

 

·                  Additions to oil and gas properties included in accounts payable of $50,000.

 

During the three months ended March 31, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Stock-based compensation expense of $868 capitalized as proved property.

 

·      Conversion of 34,600 shares of Preferred Stock into 5,766,667 shares of common stock.

 

·                  Additions to oil and gas properties included in accounts payable of $547,301.

 

Cash paid for interest during the three months ended March 31, 2012 and 2011 was $109,630 and $68,741, respectively. There was no cash paid for income taxes during the three months ended March 31, 2012 and 2011.

 

NOTE 11 — LEGAL PROCEEDINGS

 

The Company is party to various legal proceedings arising out of the normal course of business.  The most significant legal proceeding to which the Company is subject is summarized below.  The ultimate outcome of the Clean Water Act Compliance Order matter cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time.  The Company does not expect the outcome of this proceeding to have a material adverse effect on its financial position, results of operations or cash flows.

 

Clean Water Act Compliance Order Matter

 

On October 3, 2011, the Company received a compliance order from the United States Environmental Protection Agency (“EPA”) Region 8 under the authority of the federal Clean Water Act.  The compliance order alleges that the Company violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: once when it constructed an access road to a future well location in either 2004 or 2005 and once when it constructed an access road and a well pad in 2007 or 2008.  The compliance order directs the Company to remove all dredged or fill material alleged to have been placed in the wetlands and to restore the wetlands to their pre-impact condition and grade, which would require that the Company plug and abandon the well alleged to have been installed in a wetlands area.  The compliance order does not seek any civil penalties for the alleged violations.  The Company disagrees with some of the factual contentions in the compliance order, and we have had a number of discussions with the EPA concerning the order.  If a successful resolution cannot be negotiated, we intend to evaluate our options, which may include challenging the compliance order in federal court.  The Company is not able to predict the outcome of this matter at this time.

 

NOTE 12 — GUARANTOR SUBSIDIARIES

 

On August 31, 2011, the Company filed a Form S-3 shelf registration statement with the SEC, which was declared effective on September 20, 2011. Under this registration statement, the Company may from time to time offer and sell securities including common stock, preferred stock, depositary shares, warrants and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries:  Gasco Production Company, Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor

 

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Subsidiaries”). The stand-alone parent entity, Gasco Energy, Inc., has insignificant independent assets and no operations. Therefore, supplemental financial information on a condensed consolidating basis of the Guarantor Subsidiaries is not required. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the Guarantor Subsidiaries, except those imposed by applicable law.

 

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ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overview

 

We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in these areas. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

 

Recent Developments

 

Uinta Basin Joint Venture

 

On March 22, 2012, we closed a previously announced transaction (the “Uinta Basin Transaction”) whereby, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated February 23, 2012, between our wholly owned subsidiary, Gasco Production Company, and Wapiti Oil & Gas II, L.L.C. (“Wapiti”), and a Closing Agreement (the “Closing Agreement”) dated March 22, 2012 relating to the Purchase Agreement, we (i) sold to Wapiti an undivided 50% of our interest in certain of our Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti and (ii) transferred to Wapiti an undivided 50% of our interest in our Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.

 

As part of the Uinta Basin Transaction, Gasco Production Company entered into a Development Agreement (the “Development Agreement”) with Wapiti, which includes terms and conditions of a drilling program agreed to by the parties.

 

Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on our behalf, and we have agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million; provided that, if on February 23, 2013, the five-year New York Mercantile Exchange (“NYMEX”) natural gas strip pricing is at least $5.00/MMBtu, the drilling and completion program will be expanded by $6.25 million to $43.75 million with Wapiti paying for $5.0 million of the additional costs.

 

The drilling and completion program will continue until Wapiti’s funding commitment has been fully expended or for a shorter period, if the Operating Committee (as defined below) votes to cease the drilling program after Wapiti has expended $10.0 million on drilling and completion costs related to the program wells (the “Drilling Term”).  We may suspend the drilling program, including the expenditure of Wapiti’s funding commitment, for up to six months if certain governmental environmental studies have not been completed by the time that $23.6 million of Wapiti’s funding commitment has been expended.

 

With respect to wells drilled pursuant to the drilling program, the net revenue interest attributable to such wells from the closing through the time when the cumulative proceeds received by Wapiti from such wells equals the amount of costs actually paid by Wapiti in respect of such wells and the drilling program (such time, “Payout”), will be allocated 32.5% to us and 67.5% to Wapiti. After Payout, the net revenue interest will be allocated in proportion to the actual net revenue interests of the parties in such wells.  With respect to each well

 

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drilled pursuant to the drilling program, (i) all drilling and completion costs will be borne (a) during the Drilling Term, 20% by us and 80% by Wapiti, (b) after the Drilling Term but before Payout, 32.5% by us and 67.5% by Wapiti, and (c) after Payout, in proportion to the actual working interests of the parties in such wells, and (ii) all other working interest costs will be borne (x) before Payout, 32.5% by us and 67.5% by Wapiti, and (y) after Payout, in proportion to the actual working interests of the parties in such wells.

 

Subject to the terms of the Development Agreement, we will manage the operations contemplated by the drilling program.  Except for the subject assets that are already subject to joint operating agreements with third parties, the operation of (i) a portion of the subject assets will be subject to an agreed upon joint operating agreement (a “JOA”), which names Gasco Production Company as operator of record, and (ii) the remaining portion of the subject assets will be subject to an agreed upon JOA, which names Wapiti as operator of record.  Gasco Production Company and Wapiti also entered into a contract operating agreement naming Gasco Production Company as contract operator with respect to the portion of the subject assets for which Wapiti is named as operator of record.  We and Wapiti have formed an Operating Committee (the “Operating Committee”) to oversee generally the drilling program and operations in the project area and to approve certain matters specified in the Development Agreement. The Operating Committee will consist of two members from each of us and Wapiti, with the members appointed by each party having an aggregate 50% vote.

 

The Development Agreement also contains transfer restrictions on each of our and Wapiti’s ability to transfer its respective interests in the subject assets. The Development Agreement also contains a customary area of mutual interest provision covering the Project Area. With certain limited exceptions, the Development Agreement will remain in effect during the Drilling Term; however, after the six-month anniversary of the end of the Drilling Term, the Development Agreement may be terminated by either us or Wapiti upon six months’ advance notice.

 

The foregoing description of the Uinta Basin Transaction, including the Purchase Agreement, the Closing Agreement and the Development Agreement, do not purport to be complete and are qualified in their entirety by reference to the full text of the Purchase Agreement, the Closing Agreement and the Development Agreement, which are attached as exhibits to our Current Report on Form 8-K filed on March 28, 2012.

 

We used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under our credit facility, and we will use the remaining proceeds for capital expenditures, working capital, acquisitions of oil and natural gas properties and other general corporate purposes.

 

Amended and Restated Monarch Agreement

 

On March 22, 2012, we entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch Natural Gas, LLC, a Delaware limited liability company (“Monarch”), which amends, restates and replaces the Gas Gathering and Processing Agreement effective March 1, 2010, as subsequently amended by that certain letter agreement dated September 20, 2011 (the “Existing Monarch Agreement”).  Pursuant to the terms of the Existing Monarch Agreement, we dedicated the gas production from all of our Utah acreage to Monarch and Monarch agreed to provide gathering, compression and processing services to us.

 

Under the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to (a) release and waive its rights to process the first 50,000 MMBtu/day of our gas delivered to Monarch’s gathering system pursuant to the Amended and Restated Monarch Agreement (the “Excluded Production”) and (b) retain all processing rights for all gas volumes produced from certain of our reserves in excess of the Excluded Production.  The Excluded Production may be reduced if we fail to meet certain drilling investment targets.  The term of the Amended and Restated Monarch Agreement extends through February 28, 2025, and, for wells

 

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that are already connected to Monarch’s gathering system on February 28, 2025, for so long as our gas can be produced in commercial quantities from such wells.

 

Credit Facility

 

As a result of the completion of the semi-annual redeterminations of the borrowing base under our $250 million revolving credit facility, the borrowing base was decreased to $13 million effective November 1, 2011. As of December 31, 2011, there were loans in the amount of $8,544,969 and letters of credit in the amount of $25,195 outstanding under the credit facility. In March 2012, we borrowed an additional $2 million under our credit facility and effective March 22, 2012, we repaid all of the borrowings outstanding our credit facility.

 

On March 22, 2012, in connection with the consummation of the Uinta Basin Transaction, we entered into a Twelfth Amendment (the “Twelfth Amendment”) to our Credit Agreement, dated as of March 29, 2006, by and among us, certain of our subsidiaries, as guarantors, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (as amended, the “Credit Agreement”). The Twelfth Amendment, among other things, (i) extended the maturity of the credit facility to June 29, 2012, (ii) permitted the consummation of the Uinta Basin Transaction, (iii) reduced the availability of aggregate commitments under the credit facility to $25,195.25, and (iv) addressed letter of credit availability through maturity.

 

Prospect Fee

 

During January 2012, we entered into an arrangement with an exploration and production company which operates in California, pursuant to which we received a $750,000 prospect fee related to certain of our California acreage. The fee reimbursed costs that we have invested in the area and provides us with a potential carried interest of 20% in two wells to be drilled on the acreage.

 

Green River Oil Wells

 

In December 2011, we began drilling two wells to the Green River Formation, both in which we currently own a 50% working interest. These wells were successfully completed during January 2012.  The wells are on artificial lift and continue to produce oil as expected.  We expect to drill additional Green River oil wells during the second half of 2012.  The wells had seven-day average initial production rates of 67 barrels of oil per day (BOPD) and 50 BOPD, respectively.  After nearly 90 days of production, the wells have averaged approximately 21 and 15 BOPD and both have now stabilized at approximately these same average rates.

 

Natural Gas Completion Operations

 

During the first quarter of 2012, we recompleted 1.0 gross natural gas well (0.85 net) to target up-hole pay zones in existing wellbores.  We currently have an inventory of 14 operated wells with up-hole recompletions and one Upper Mancos well awaiting initial completion activities.  We contract drilling rigs as needed and do not currently have a rig under contract at this time.  Increased activity in drilling natural gas wells and in recompletions is scheduled to commence during the second half of 2012.  We currently operate 135 gross wells.

 

Director Stock Appreciation Right and Stock Option Grants

 

Effective October 1, 2011, our non-employee directors agreed to reduce their monthly compensation and in exchange, on October 5, 2011, we granted stock appreciation rights (the “October SARs”) related to a total of 500,000 shares of our common stock to these directors. The October SARs provided the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) the fair market value of one share of

 

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common stock on the date of exercise, over (ii) $0.25, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised (“Appreciation Amount”). The October SARs vested on January 31, 2012 and were automatically exercised on February 1, 2012. Since the market value of the common stock was lower than $0.25, no payments were made.

 

Effective February 28, 2012, we granted another SARs award (“February SARs”) related to a total of 1,000,000 shares of our common stock to these directors.  The February SARs provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) (A) the fair market value of one share of common stock on the date of exercise or (B) $2.00, whichever is greater, over (ii) $0.30, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised. The February SARs vest on January 31, 2013 and will be automatically exercised on February 1, 2013.

 

Additionally, effective February 28, 2012, we granted a total of 500,000 options to purchase common stock with a strike price of $0.30 per share to our non-employee directors. The options have a two-year vesting period and expire five years from the grant date.

 

Appointment of New Vice President of Business Development and Operations

 

Effective March 1, 2012, we hired Mr. Richard P. Crist as Vice President, Business Development and Exploration, a newly created position that will add additional experience and expertise to our senior management team.

 

Oil and Gas Production Summary

 

The following table presents our production and price information during the three months ended March 31, 2012 and 2011. The Mcfe calculations assume a conversion of six Mcf for each Bbl of oil.

 

 

 

For the Three Months
Ended March 31,

 

Quarter over Quarter
Change

 

 

 

2012

 

2011

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

831,767

 

913,075

 

(81,308

)

(9

)%

Average sales price per Mcf

 

$

2.77

 

$

4.06

 

$

(1.29

)

(32

)%

 

 

 

 

 

 

 

 

 

 

Oil production (Bbl)

 

9,885

 

7,574

 

2,311

 

31

%

Average sales price per Bbl

 

$

88.26

 

$

74.74

 

$

13.52

 

18

%

 

 

 

 

 

 

 

 

 

 

Production (Mcfe)

 

891,077

 

958,519

 

(67,442

)

(7

)%

 

Our equivalent oil and gas production decreased by 7% during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011, primarily due to the Unita Basin Transaction and normal production declines.

 

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Liquidity and Capital Resources

 

General

 

We generate cash from operations from the sale of oil and natural gas, and have relied in the past primarily on the issuance of equity, borrowings under our revolving credit facility and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and leases.  For the quarter ended March 31, 2012, we incurred a net loss of $5,038,133.  As of March 31, 2012, we had an accumulated deficit of $227,633,909.

 

On March 22, 2012, we closed the Uinta Basin Transaction, pursuant to which we (i) sold to Wapiti an undivided 50% interest in certain of our Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti and (ii) transferred to Wapiti an undivided 50% of our interest in our Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.

 

Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on our behalf, and we have agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million; provided that, if on February 23, 2013, the five-year New York Mercantile Exchange (“NYMEX”) natural gas strip pricing is at least $5.00/MMBtu, the drilling and completion program will be expanded by $6.25 million to $43.75 million with Wapiti paying for $5.0 million and us paying for $1.25 million of the additional costs.

 

We used approximately $10.5 million of the proceeds from the Uinta Basin Transaction to repay outstanding borrowings under our revolving credit facility, and we will use the remaining proceeds for capital expenditures consisting approximately $5.0 million for our drilling program which includes the drilling of 13 wells, our continued up-hole recompletion program targeting natural gas and for additional investment in existing and new California oil and gas prospects in the San Joaquin Basin as well as for working capital, acquisitions of oil and natural gas properties and other general corporate purposes.

 

Our revolving credit facility will mature in June 2012, at which time we will be required to repay all of the outstanding borrowings thereunder. We are discussing alternative borrowing arrangements with other lenders and while we currently believe that we will be able to find a replacement lender, there can be no assurance that we will be able to obtain adequate alternative financing on acceptable terms or at all.  For example, our recent results of operations and volatility in oil and gas prices, as well as in the domestic credit and capital markets generally, may negatively affect the availability and terms of financing.  If we were to secure an alternative borrowing arrangement, we expect that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of our current revolving credit facility.  If we are unable to secure an alternative borrowing arrangement, we will lose a primary source of liquidity and be required to fund our business and operations going forward without outside capital.

 

We believe that cash on hand (including proceeds from the Uinta Basin Transaction) as well as future cash flow from operations will be sufficient to fund our anticipated cash requirements for working capital purposes and normal capital expenditures through the first quarter of 2013.  However, there can be no assurance regarding these matters given that we will require significant additional capital to fund our future drilling activities and to meet our future debt maturities.  Failure to generate operating cash flow or to obtain additional financing for the development of our properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospectus with the possible loss of our properties.  This could cause us to alter our business plans, including further reducing our

 

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exploration and development plans.

 

In particular, we face uncertainties relating to our ability to generate sufficient cash flows from operations to fund the level of capital expenditures required for oil and gas exploration and production activities and for working capital purposes. We intend to fund our anticipated cash requirements through the first quarter of 2013, including our 2012 capital budget of $5.0 million, primarily through cash on hand and cash flows from operations, although we cannot assure you that cash on hand and cash flows from operations will be sufficient to fund such requirements.

 

Our inability to secure replacement financing for the revolving credit facility or otherwise access future borrowings will significantly limit our ability to fund or increase our operating budget and to execute our growth plans, and our liquidity and results of operations may be materially adversely affected.  If we need additional liquidity for future activities, we may be required to consider several options for raising such funds, such as selling additional securities, selling assets or executing farm-out or similar arrangements, but we may be unable to complete any of these transactions on terms acceptable to us or at all.  Any financing obtained through the sale of our equity will likely result in substantial dilution to our stockholders.

 

Sources and Uses of Funds

 

The following table summarizes our sources and uses of cash for each of the three months ended March 31, 2012 and 2011.

 

 

 

For the Three Months Ended
March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Net cash provided by operations

 

$

(491,955

)

$

917,789

 

Net cash provided by (used in) investing activities

 

15,056,080

 

(2,749,810

)

Net cash (used in) provided by financing activities

 

(8,565,912

)

935,000

 

Net increase (decrease) in cash

 

5,998,213

 

(897,021

)

 

Cash provided by operations decreased by $1,409,744 from March 31, 2011 to March 31, 2012.  The decrease in cash provided by operations was primarily due to a $1,088,838 decrease in oil and gas revenue caused by a 7% decrease in equivalent production and a 32% decrease in gas prices partially offset by an 18% increase in the oil prices received during the first quarter of 2012, and a $379,490 increase in workover expenses during the first quarter of 2012.

 

Our investing activities during the first quarters of 2012 and 2011 included our development and exploration activities, fixed asset additions and the change in advances from joint interest owners. The investing activity during the first quarter of 2012 also included the sales proceeds from the Uinta Basin Transaction (see Note 3 — Asset Sales of the accompanying unaudited condensed consolidated financial statements).

 

The financing activity during the first three months of 2012 included $2.0 million in borrowings and $10,544,969 of repayments under our revolving credit facility and the payment of a deposit of $20,943. The financing activity during the first three months of 2011 included $1.0 million in borrowings under our revolving credit facility and the payment of $65,000 in costs associated with the issuance of our 5.5% Convertible Senior Notes due 2015 (“2015 Notes”).

 

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2012 Capital Budget

 

Our initial capital expenditure budget for our 2012 oil and natural gas activities which is subject to final Board of Director approval has been set at $5.0 million. The 2012 capital expenditure budget will be allocated among our drilling program which includes the drilling of 13 wells, our continued up-hole recompletion program targeting natural gas and our additional investment in existing and new California oil and natural gas prospects in the San Joaquin Basin. Our 2012 capital expenditure program will be funded primarily from cash received from the closing of the Uinta Basin Transaction, cash on hand and cash flow from operations. See “Liquidity and Capital Resources” above.

 

Risk Management

 

We use commodity derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk.  However, these derivative instruments may limit the prices we actually realize and therefore may reduce oil and natural gas revenues in the future. The fair value of our oil and natural gas derivative instruments (excluding the warrant derivative financial instrument) outstanding as of March 31, 2012 was a current asset of $1,062,071. See Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on our risk management policies.

 

Results of Operations

 

The First Quarter of 2012 Compared to the First Quarter of 2011

 

Oil and Gas Revenue and Production

 

The table below sets forth the production volumes, price and revenue by product for the periods presented.

 

 

 

Three Months Ended March
31,

 

Quarter over Quarter Change

 

 

 

2012

 

2011

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

831,767

 

913,075

 

(81,308

)

(9

)%

Average sales price per Mcf

 

$

2.77

 

$

4.06

 

$

(1.29

)

(32

)%

Natural gas revenue

 

$

2,307,864

 

$

3,703,031

 

$

(1,395,167

)

(38

)%

 

 

 

 

 

 

 

 

 

 

Oil production (Bbl)

 

9,885

 

7,574

 

2,311

 

31

%

Average sales price per Bbl

 

$

88.26

 

$

74.74

 

$

13.52

 

18

%

Oil revenue

 

$

872,403

 

$

566,074

 

$

306,329

 

54

%

 

 

 

 

 

 

 

 

 

 

Total oil and gas revenue

 

$

3,180,267

 

$

4,269,105

 

$

(1,088,838

)

(26

)%

 

 

 

 

 

 

 

 

 

 

Equivalent production (Mcfe)

 

891,077

 

958,519

 

(67,442

)

(7

)%

 

The decrease in oil and gas revenue of $1,088,838 during the first quarter of 2012 compared with the first quarter of 2011 was comprised of a 7% decrease in equivalent oil and gas production and a 32% decrease in gas prices from $4.06 in 2011 to $2.77 in 2012 partially offset by an 18% increase in average oil prices of $13.52 per Bbl of oil. The decrease in equivalent oil and gas production was primarily due to the Unita Basin Transaction and normal production declines. The $1,088,838 decrease in oil and gas revenue during the first

 

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quarter of 2012 represents a decrease of $155,545 related to the equivalent production decrease and a decrease of $933,293 related to the decrease in gas prices partially offset by an increase in oil prices.

 

Lease Operating Expenses

 

The table below sets forth the detail of oil and gas lease operating expenses during the periods presented.

 

 

 

For the Three Months
Ended March 31,

 

Quarter over Quarter
Change

 

 

 

2012

 

2011

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Direct operating expenses and overhead

 

$

922,702

 

$

812,146

 

$

110,556

 

14

%

Workover expense

 

704,639

 

325,149

 

379,490

 

117

%

Total operating expenses

 

$

1,627,341

 

$

1,137,295

 

$

490,046

 

43

%

Operating expenses per Mcfe

 

$

1.82

 

$

1.19

 

$

0.63

 

53

%

 

 

 

 

 

 

 

 

 

 

Production and property taxes

 

$

69,830

 

$

204,137

 

$

134,307

 

(66

)%

Production and property taxes per Mcfe

 

$

0.08

 

$

0.21

 

$

(0.13

)

(62

)%

 

 

 

 

 

 

 

 

 

 

Total lease operating expense

 

$

1,697,171

 

$

1,341,432

 

$

355,739

 

26

%

 

 

 

 

 

 

 

 

 

 

Total lease operating expense per Mcfe

 

$

1.90

 

$

1.40

 

$

0.50

 

36

%

 

Lease operating expense increased $355,739 during the first quarter of 2012 compared with the first quarter of 2011. The increase is primarily due to higher workover expenses related to the removal of critical velocity reduction strings, modification of cap strings and scale treatment and removal from existing wells during the first quarter of 2012 partially offset by decreased severance taxes related to a tax exemption for certain of our wells.

 

Transportation and Processing

 

Transportation and processing costs of $656,972 ($0.74 per Mcfe) and $801,715 ($0.84 per Mcfe) as of March 31, 2012 and 2011, respectively, represent the costs we incurred to transport and process the gas production from our wells. The decrease of $141,743 in these expenses during the first quarter of 2012 reflects lower transportation and processing costs related to the 7% decrease in gas production previously discussed.

 

Depletion, Depreciation, Amortization and Accretion

 

Depletion, depreciation and amortization expense during the first quarters of 2012 and 2011 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. This expense remained fairly consistent during the first quarter of 2012 compared to the first quarter of 2011 primarily due to the production decline combined with the decrease in the full cost pool resulting from the Uinta Basin Transaction during March 2012.

 

Impairment

 

As of March 31, 2012, our full cost pool exceeded the ceiling limitation based on the average, first-day-of-the-

 

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month oil and gas prices of $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012. Therefore, impairment expense of $4,300,000 was recorded during the quarter ended March 31, 2012.

 

Gain on Sale of Assets, net

 

The gain on sale of assets, net during the first quarter of 2012 represents the sale of certain of our inventory.

 

General and Administrative Expense

 

The following table summarizes the components of general and administrative expense and stock-based compensation expense incurred during the periods presented.

 

 

 

For the Three Months
Ended March 31,

 

Quarter over Quarter
Change

 

 

 

2012

 

2011

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Total general and administrative costs

 

$

1,686,360

 

$

1,381,260

 

$

305,100

 

22

%

General and administrative costs allocated to drilling, completion and operating activities

 

(341,383

)

(424,997

)

(83,614

)

(20

)%

General and administrative expense

 

$

1,344,977

 

$

956,263

 

$

388,714

 

41

%

General and administrative expenses per Mcfe

 

$

1.51

 

$

1.00

 

$

0.51

 

51

%

 

 

 

 

 

 

 

 

 

 

Total stock-based compensation costs

 

$

60,205

 

$

170,768

 

$

(110,563

)

(65

)%

Stock-based compensation costs capitalized

 

(200

)

(868

)

668

 

77

%

Stock-based compensation

 

$

60,005

 

$

169,900

 

$

(109,895

)

(65

)%

Stock-based compensation per Mcfe

 

$

0.07

 

$

0.18

 

$

(0.11

)

(61

)%

 

 

 

 

 

 

 

 

 

 

Total general and administrative expense including stock-based compensation

 

$

1,404,982

 

$

1,126,163

 

$

278,819

 

25

%

 

 

 

 

 

 

 

 

 

 

Total general and administrative expense per Mcfe

 

$

1.58

 

$

1.18

 

$

0.40

 

33

%

 

General and administrative expense increased by $278,819 during the first quarter of 2012 as compared with the first quarter of 2011 primarily due to the legal and consulting expenses associated with the Uinta Basin Transaction partially offset by a $109,895 decrease in stock-based compensation as the result of the vesting of certain stock options

 

Interest Expense

 

Interest expense decreased $135,126 during the first quarter of 2012 as compared with the first quarter of 2011, primarily due to the reduction our borrowing base during May and November of 2011.

 

Derivative (Losses) Gains

 

Derivative (losses) gains during the first quarters of March 31, 2012 and 2011 are comprised of realized and unrealized gains and losses on our commodity derivative instruments and unrealized gains on our warrant derivative liability. The unrealized derivative (losses) gains represent the changes in the fair value of our derivative assets and liabilities and the realized derivative gains represent the net settlements from our commodity derivative counterparty based on each month’s settlement during the quarter.

 

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Amortization of Deferred Income from Sale of Assets

 

The amortization of the deferred income from the sale of assets represents the amortization of the excess of proceeds received over the carrying value of our gathering system and evaporative facilities sold during March 2010.

 

Off-Balance Sheet Arrangements

 

From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2012, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

 

Recently Issued Accounting Pronouncements

 

Effective January 1, 2012, we adopted Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards.” The adoption of ASU 2011-04 did not have a significant impact on our consolidated financial position or results of operations.

 

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ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2011 10-K.

 

We are exposed to a variety of market risks, including commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at March 31, 2012, and from which we may incur future gains or losses from changes in commodity prices or market interest rates. We do not enter into derivative or other financial instruments for speculative or trading purposes.

 

Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analyses are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in commodity prices and interest rates, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

 

Further, our cash equivalents and derivative instruments are exposed to concentrations of credit risk. We manage and control this risk by placing these funds and contracts with major financial institutions with high credit ratings.   Our receivables are comprised of oil and gas revenue receivables and joint interest billings receivable, which amounts are due from a limited number of entities. Therefore, collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized; however, to date, we have had minimal bad debts.

 

Commodity Price Risk

 

Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of our exposure to adverse market changes, we have entered into various derivative instruments. As of March 31, 2012, our derivative instruments consisted of one costless collar agreement for our production from January 1, 2012 through December 31, 2012. At recent production levels, approximately 33% of our net production volumes have been hedged through this instrument. The counterparty in this instrument is the Administrative Agent under our revolving credit facility. As of March 31, 2012, the fair value of this agreement is a current asset of $1,062,071. This instrument allows us to predict with greater certainty the effective natural gas prices to be received for our hedged production. Our costless collar contains a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments will be due from either party.

 

The collar contract allows us to predict with greater certainty the effective natural gas prices that we will receive for our hedged production and to benefit from operating cash flows when market prices are less than the fixed prices of the contract. However, we will not benefit from market prices that are higher than the fixed prices in the contract for the hedged production. Our collar contract has no requirements for us to post additional collateral based upon the changes in the market value of the hedge instrument.

 

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Our costless collar agreement as of March 31, 2012 is summarized in the table below:

 

Agreement
Type

 

Remaining
Term

 

Quantity

 

Index
Price (a)

 

Call Price
Counterparty
buyer

 

Put Price
Gasco buyer

Costless collar

 

4/12 – 12/12

 

2,000 MMBtu/day

 

NW Rockies

 

$4.25/MMBtu

 

$5.12/MMBtu

 


(a)           Northwest Pipeline Rocky Mountains — Inside FERC first-of-month index price.

 

The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the three months ended March 31, 2012 and including the impact of the collar contract in place as of March 31, 2012, our annual revenue would increase or decrease by approximately $39,000 for each $1.00 per barrel change in crude oil prices and $333,000 for each $0.10 per Mcf change in natural gas prices.

 

Warrant Derivative Risk

 

On June 15, 2011, we issued the June Warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, we issued the August Warrants to purchase 11,500,000 shares of common stock.  The Warrants have an  initial exercise price of $0.35 per share (subject to adjustment) with a sixty-month term, as further described in Note 2 — Significant Accounting Policies of the accompanying unaudited condensed consolidated financial statements.  The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques are highly volatile and sensitive to changes in the trading price of our common stock, which has a high-historical volatility. With all other factors remaining constant as of March 31, 2012:

 

(i)             the warrant derivative liability would decrease by approximately $2.2 million for a $0.10 decrease in the trading price of our common stock and would increase by approximately $2.6 million for a $0.10 increase in the trading price of our common stock; and

(ii)          the warrant derivative liability would increase by approximately $490,000 by a 10% increase in the volatility rate and would decrease by approximately $417,000 by a 10% decrease in the volatility rate.

 

Interest Rate Risk

 

We do not currently use interest rate derivatives to mitigate our exposure to interest rate risk, including under our revolving credit facility, to the volatility in interest rates. During March 2012, we repaid all amounts outstanding under our revolving credit facility.

 

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ITEM 4 - CONTROLS AND PROCEDURES

 

Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us 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 SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow such persons to make timely decisions regarding required disclosures.

 

Based upon the results of our evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2012, at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f)  under the Securities Exchange Act of 1934) during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II - OTHER INFORMATION

 

Item 1 -                                 Legal Proceedings

 

For a discussion of our legal proceedings please see Note 11 — Legal Proceedings of the accompanying unaudited condensed consolidated financial statements included herein.  We do not expect the outcome of the proceedings discussed therein to have a material adverse affect on our financial position, results of operations or cash flows.

 

Item 1A -                        Risk Factors

 

There have been no material changes in our risk factors as previously disclosed in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors discussed in our 2011 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Quarterly Report and in our 2011 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

 

Item 6 —     Exhibits

 

The following is a list of exhibits filed or furnished (as indicated) as part of this Quarterly Report.  Where so noted, exhibits which were previously filed are incorporated herein by reference.

 

43



Table of Contents

 

Exhibit Number

 

Exhibit

 

 

 

2.1

 

Purchase and Sale Agreement dated February 23, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

2.2

 

Development Agreement dated March 22, 2012, between Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

2.3

 

Closing Agreement dated March 22, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.3 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

3.1

 

Restated and Amended Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

 

 

 

3.2

 

Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).

 

 

 

3.3

 

Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).

 

 

 

3.4

 

Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).

 

 

 

3.5

 

Certificate of Amendment to Articles of Incorporation, dated September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated September 15, 2010, filed on September 20, 2010, File No. 001-32369).

 

 

 

3.6

 

Certificate of Designations, Preferences and Rights of Series B Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).

 

 

 

3.7

 

Certificate of Designation for Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).

 

 

 

10.1

 

Twelfth Amendment to the Credit Agreement dated as of March 22, 2012, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco

 

44



Table of Contents

 

 

 

Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

10.2

 

Amended and Restated Gas Gathering and Processing Agreement dated March 22, 2012, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

10.3#

 

Form of Stock Appreciation Right Agreement. (incorporated herein by reference to Exhibit 10.35 to the Company’s Form 10-K dated March 28, 2012, filed on March 28, 2009, File No. 001-32369).

 

 

 

31.1*

 

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

 

 

 

31.2*

 

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

 

 

 

32.1**

 

Section 1350 Certification of Chief Executive Officer.

 

 

 

32.2**

 

Section 1350 Certification of Chief Financial Officer.

 

 

 

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 Taxonomy Extension Definition Linkbase Document

 


*                 Filed herewith.

**          Furnished herewith.

***   Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

#                 Identifies management contracts and compensatory plans or arrangements.

 

45



Table of Contents

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

GASCO ENERGY, INC.

 

 

 

 

Date: May 1, 2012

By:

/s/ Peggy A. Herald

 

 

Peggy A. Herald, Vice President and

 

 

Chief Accounting Officer

 

 

(Principal Financial Officer

 

 

and Duly Authorized Officer)

 

46



Table of Contents

 

EXHIBIT INDEX

 

Exhibit Number

 

Exhibit

2.1

 

Purchase and Sale Agreement dated February 23, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

2.2

 

Development Agreement dated March 22, 2012, between Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

2.3

 

Closing Agreement dated March 22, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.3 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

3.1

 

Restated and Amended Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

 

 

 

3.2

 

Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).

 

 

 

3.3

 

Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).

 

 

 

3.4

 

Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).

 

 

 

3.5

 

Certificate of Amendment to Articles of Incorporation, dated September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated September 15, 2010, filed on September 20, 2010, File No. 001-32369).

 

 

 

3.6

 

Certificate of Designations, Preferences and Rights of Series B Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).

 

 

 

3.7

 

Certificate of Designation for Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).

 

47



Table of Contents

 

10.1

 

Twelfth Amendment to the Credit Agreement dated as of March 22, 2012, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

10.2

 

Amended and Restated Gas Gathering and Processing Agreement dated March 22, 2012, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

 

 

 

10.3#

 

Form of Stock Appreciation Right Agreement. (incorporated herein by reference to Exhibit 10.35 to the Company’s Form 10-K dated March 28, 2012, filed on March 28, 2009, File No. 001-32369).

 

 

 

31.1*

 

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

 

 

 

31.2*

 

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

 

 

 

32.1**

 

Section 1350 Certification of Chief Executive Officer.

 

 

 

32.2**

 

Section 1350 Certification of Chief Financial Officer.

 

 

 

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 Taxonomy Extension Definition Linkbase Document

 


*                 Filed herewith.

**          Furnished herewith.

***   Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

#                 Identifies management contracts and compensatory plans or arrangements.

 

48


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