10-Q 1 a13-19575_110q.htm 10-Q

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 September 30, 2013

 

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

(State or other jurisdiction of

incorporation or organization)

 

98-0204105
(I.R.S. Employer

Identification No.)

 

7979 E. Tufts Avenue, Suite 1150, Denver, Colorado 80237

(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.  (Check one):

 

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 November 8, 2013:    563,532,352

 

 

 



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Table of Contents

 

PART I — FINANCIAL INFORMATION

 

 

Cautionary Statement Regarding Forward-Looking Statements

3

 

 

Glossary of Natural Gas and Oil Terms

5

 

 

 

Item 1.

Financial Statements (Unaudited)

8

 

Condensed Consolidated Balance Sheets

8

 

Condensed Consolidated Statements of Operations

10

 

Condensed Consolidated Statements of Cash Flows

12

 

Notes to Unaudited Condensed Consolidated Financial Statements

13

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

36

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

50

 

 

 

Item 4.

Controls and Procedures

51

 

 

 

PART II — OTHER INFORMATION

 

 

 

Item 1.

Legal Proceedings

52

 

 

 

Item 1A.

Risk Factors

52

 

 

 

Item 3.

Defaults Upon Senior Securities

52

 

 

 

Item 6.

Exhibits

52

 

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Cautionary Statement Regarding Forward-Looking Statements

 

Some of the information in this Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended.  All statements other than statements of historical fact included in this report, including, without limitation, statements regarding Gasco Energy, Inc. and its consolidated subsidiaries’ (collectively, “Gasco,” the “Company,” “we,” “our” or “us”) future financial position, expectations with respect to liquidity, capital resources and ability to continue as a going concern, common stock, business strategy, budgets, projected costs and plans and objectives 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 on Form 10-Q or otherwise expressed by us are, to the knowledge and in the judgment of our management, believed to be reasonable when made, 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 may be affected by inaccurate assumptions, and 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 expectation projection, estimate or forecasted result.  The key factors that may cause actual results to vary from those the Company expects are discussed in (1) Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Part II, Item 1A “Risk Factors,” Part II, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and elsewhere herein, (2) Part I, Item 1A “Risk Factors,” Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk,” and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2012, and (3) our reports and registration statements filed from time to time with the Securities and Exchange Commission. 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 and adversely from any projected, forecasted, estimated or budgeted amounts or events that we have discussed in this report:

 

·                  our ability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures, meet working capital needs and our related ability to continue as a going concern;

 

·                  the volatility and decline in our stock price, and the ability of our common stock to remain traded on the OTCQB Marketplace;

 

·                  our ability to meet our firm commitment delivery obligations in our gathering, transportation and processing agreements or otherwise satisfy minimum volume deficiency payment obligations;

 

·                  our ability to maintain relationships with suppliers, customers, employees, stockholders and other third parties in light of our current liquidity situation and recent results of operations;

 

·                  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

 

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ability to produce economically;

 

·                  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 commodity price exposure;

 

·                  any failure by the gathering, transportation or processing facilities of our natural gas, which would negatively affect our ability to deliver our natural gas production for sale;

 

·                  marketing of oil and natural gas;

 

·                  pipeline constraints;

 

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

 

·                  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; and

 

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

 

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.  The Company’s forward-looking statements speak only as of the date made. We assume no duty to update or revise our 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 on Form 10-Q.

 

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.

 

BOE. Barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

BOE/d. One BOE per day.

 

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.

 

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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.

 

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 Securities and Exchange Commission 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

 

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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.

 

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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PART I — FINANCIAL INFORMATION

 

ITEM I — FINANCIAL STATEMENTS

 

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

September 30,

 

December 31,

 

 

 

2013

 

2012

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

2,008,434

 

$

2,938,086

 

Accounts receivable

 

 

 

 

 

Joint interest billings

 

1,760,277

 

1,753,204

 

Revenue

 

780,952

 

777,567

 

Inventory

 

359,515

 

1,730,733

 

Inventory held for sale

 

351,575

 

 

Prepaid expenses

 

14,370

 

153,848

 

Total

 

5,275,123

 

7,353,438

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, at cost

 

 

 

 

 

Oil and gas properties (full cost method)

 

 

 

 

 

Proved properties

 

265,443,594

 

264,814,427

 

Unproved properties

 

31,717,970

 

31,486,314

 

Facilities and equipment

 

1,522,990

 

1,493,314

 

Furniture, fixtures and other

 

504,441

 

506,511

 

Total

 

299,188,995

 

298,300,566

 

Less accumulated depletion, depreciation, amortization and impairment

 

(254,367,017

)

(253,176,523

)

Total

 

44,821,978

 

45,124,043

 

 

 

 

 

 

 

NONCURRENT ASSETS

 

 

 

 

 

Deposits

 

551,370

 

531,443

 

Deferred financing costs

 

629,361

 

845,367

 

Total

 

1,180,731

 

1,376,810

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

51,277,832

 

$

53,854,291

 

 

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)

 

 

 

September 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

5.5% Convertible Senior Notes due 2015, net of unamortized discount of $14,731,680

 

$

30,436,320

 

$

 

Accounts payable

 

1,569,713

 

1,548,121

 

Revenue payable

 

2,914,938

 

2,454,282

 

Advances from joint interest owners

 

47,667

 

47,667

 

Accrued interest

 

2,495,022

 

586,556

 

Accrued expenses

 

236,000

 

396,000

 

Total

 

37,699,660

 

5,032,626

 

 

 

 

 

 

 

NONCURRENT LIABILITIES

 

 

 

 

 

5.5% Convertible Senior Notes due 2015, net of unamortized discount of $18,530,539

 

 

26,637,461

 

Deferred income from sale of assets

 

2,311,338

 

2,463,177

 

Asset retirement obligation

 

876,201

 

815,660

 

Derivative instruments

 

71,000

 

907,500

 

Deferred rent

 

283,718

 

294,236

 

Total

 

3,542,257

 

31,118,034

 

 

 

 

 

 

 

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 September 30, 2013 and December 31, 2012

 

182

 

182

 

Common stock - $0.0001 par value; 600,000,000 shares authorized; 169,731,980 shares issued and 169,658,280 outstanding as of September 30, 2013 and 169,823,681 shares issued and 169,749,981 outstanding as of December 31, 2012

 

16,973

 

16,982

 

Additional paid-in capital

 

262,764,582

 

262,624,918

 

Accumulated deficit

 

(252,615,527

)

(244,808,156

)

Less cost of treasury stock of 73,700 common shares

 

(130,295

)

(130,295

)

Total

 

10,035,915

 

17,703,631

 

 

 

 

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

51,277,832

 

$

53,854,291

 

 

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
September 30,

 

 

 

2013

 

2012

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Gas

 

$

1,973,446

 

$

1,450,782

 

Oil

 

526,879

 

357,843

 

Total

 

2,500,325

 

1,808,625

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

Lease operating

 

815,295

 

975,520

 

Transportation and processing

 

820,411

 

326,861

 

Depletion, depreciation, amortization and accretion

 

356,480

 

524,995

 

Impairment

 

789,143

 

1,016,000

 

General and administrative

 

904,701

 

1,154,063

 

Total

 

3,686,030

 

3,997,439

 

 

 

 

 

 

 

OPERATING LOSS

 

(1,185,705

)

(2,188,814

)

 

 

 

 

 

 

OTHER (EXPENSE) INCOME

 

 

 

 

 

Interest expense

 

(2,077,831

)

(1,752,716

)

Derivative gains

 

104,000

 

720,000

 

Amortization of deferred income from sale of assets

 

50,613

 

50,613

 

Interest income

 

 

7

 

Total

 

(1,923,218

)

(982,096

)

 

 

 

 

 

 

NET LOSS

 

$

(3,108,923

)

$

(3,170,910

)

 

 

 

 

 

 

NET LOSS PER COMMON SHARE — BASIC AND DILUTED

 

$

(0.02

)

$

(0.02

)

 

 

 

 

 

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC AND DILUTED

 

169,554,076

 

169,324,481

 

 

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)

 

 

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

Gas

 

$

5,793,536

 

$

5,031,824

 

Oil

 

1,439,290

 

1,560,941

 

Total

 

7,232,826

 

6,592,765

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

Lease operating

 

2,416,559

 

3,815,987

 

Transportation and processing

 

2,179,655

 

1,502,224

 

Depletion, depreciation, amortization and accretion

 

1,125,258

 

2,023,261

 

Impairment

 

1,019,643

 

9,071,000

 

General and administrative

 

3,364,092

 

3,671,664

 

Total

 

10,105,207

 

20,084,136

 

 

 

 

 

 

 

OPERATING LOSS

 

(2,872,381

)

(13,491,371

)

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

Interest expense

 

(5,923,329

)

(5,141,430

)

Gain on sale of assets

 

 

2,567,574

 

Derivative gains

 

836,500

 

2,508,090

 

Amortization of deferred income from sale of assets

 

151,839

 

151,839

 

Interest income

 

 

24,685

 

Total

 

(4,934,990

)

110,758

 

 

 

 

 

 

 

NET LOSS

 

$

(7,807,371

)

$

(13,380,613

)

 

 

 

 

 

 

NET LOSS PER COMMON SHARE — BASIC AND DILUTED

 

$

(0.05

)

$

(0.08

)

 

 

 

 

 

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC AND DILUTED

 

169,554,076

 

168,814,549

 

 

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)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2013

 

2012

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net loss

 

$

(7,807,371

)

$

(13,380,613

)

Adjustment to reconcile net loss to net cash provided by (used in) operating activities:

 

 

 

 

 

Depletion, depreciation, amortization, accretion and impairment expense

 

2,144,901

 

11,094,261

 

Stock-based compensation

 

139,655

 

215,947

 

Change in fair value of derivative instruments

 

(836,500

)

(1,252,142

)

Gain on sale of assets

 

 

(2,567,574

)

Amortization of debt discount, deferred expenses and other

 

3,852,508

 

3,013,155

 

Payment of deposit

 

(19,927

)

(38,138

)

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(10,458

)

13,338

 

Inventory

 

 

(1,463

)

Note receivable

 

 

500,000

 

Prepaid expenses

 

139,478

 

110,266

 

Accounts payable

 

539,592

 

(1,111,826

)

Revenue payable

 

460,656

 

538,338

 

Accrued interest

 

1,908,466

 

621,060

 

Accrued expenses

 

(160,000

)

(142

)

Net cash provided by (used in) operating activities

 

351,000

 

(2,245,533

)

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Cash paid for acquisitions, development and exploration

 

(1,280,652

)

(4,522,011

)

Cash paid for furniture, fixtures and other

 

 

(205,774

)

Proceeds from sale of assets

 

 

19,192,321

 

Decrease in advances from joint interest owners

 

 

(50,845

)

Net cash (used in) provided by investing activities

 

(1,280,652

)

14,413,691

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings under line of credit

 

 

2,000,000

 

Repayment of borrowings

 

 

(10,544,969

)

Net cash used in financing activities

 

 

(8,544,969

)

 

 

 

 

 

 

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

 

(929,652

)

3,623,189

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS:

 

 

 

 

 

BEGINNING OF PERIOD

 

2,938,086

 

1,965,967

 

END OF PERIOD

 

$

2,008,434

 

$

5,589,156

 

 

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 AND NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012

 

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 generate and develop 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, 2012 (“2012 10-K”) filed with the SEC on March 6, 2013. The current interim period financial statements included herein should be read in conjunction with the financial statements and accompanying notes, including Note 3 — Significant Accounting Policies, contained in the 2012 10-K.

 

NOTE 2 — GOING CONCERN

 

The accompanying unaudited condensed consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements.  As such, the accompanying unaudited condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets, carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

 

Due to the extended decline in the natural gas market and low natural gas prices in recent years caused primarily by excess production, the Company has not been able to recover its exploration and development costs as anticipated.  As such, there is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations, and the Company currently anticipates that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital through February 2014. This expectation has been revised from management’s previous estimate included in the Form 10-Q for the quarter ended June 30, 2013 due to the completion of the October 2013 restructuring transactions discussed below, the implementation of cost savings measures and cash management strategies. This estimate is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of the Company’s cash management strategy discussed below, some or all of which may not prove to be correct

 

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and may result in the Company’s inability to meet cash requirements prior to the end of February 2014.   As a result of these factors, there is substantial doubt about the Company’s ability to continue as a going concern.

 

As of September 30, 2013, the Company had $45,168,000 aggregate principal and accrued interest of $2,495,022 outstanding under its 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”). The Company elected not to make two of the $1,242,120 semi-annual interest payments due on April 5 and October 5, 2013 on its outstanding 2015 Notes.  The 2015 Notes require the Company to pay interest on overdue interest payments at a rate of 7.5% per annum.

 

Because the Company did not make the April 5, 2013 interest payment prior to the expiration of the 30-day cure period, an event of default occurred under the Indenture.  As a result of the event of default, the Trustee or the holders of at least 25% in aggregate principal amount of the 2015 Notes had the right to declare the 2015 Notes immediately due and payable at their principal amount together with accrued interest. The Company did not receive any notice of acceleration of the 2015 Notes; however, as of October 17, 2013, the 2015 Notes and accrued interest were cancelled in the restructuring transactions further described in Note 4 — Restructuring Transaction, herein. As of September 30, 2013, the 2015 Notes were classified as a current obligation in the accompanying unaudited condensed consolidated financial statements.

 

The Company has been seeking to restructure or refinance its debt or sell assets to improve its liquidity position since mid-year 2012. During this period, the Company has operated without a credit facility, has been delisted from the NYSE MKT LLC (the “Exchange”), and had defaulted under the 2015 Notes.

 

The Company and Stephens Inc., the Company’s financial advisor, conducted a process to evaluate various strategic alternatives.  The restructuring agreements resulting from this process involve an investment in the Company by Markham LLC (“Markham”) and Orogen Energy, Inc. (“Orogen”). On October 17, 2013, these investors acquired the $45,168,000 aggregate principal amount of the Company’s 2015 Notes and accrued interest thereon, all 182,065 outstanding Series C convertible preferred shares (“Series C Stock”) and common shares owned by the holders of the 2015 Notes. Then on October 18, 2013, the investors exchanged the 2015 Notes, accrued interest and Series C Stock for 393,550,372 shares of the Company’s common stock and 50,000 shares of the newly-created Series D convertible preferred stock (“Series D Stock”) (the “Restructuring Transactions”). See Note 4 — Restructuring Transactions, herein for further discussion of the Restructuring Transactions. As a result of the Restructuring Transactions, the new investors now have fully-diluted control of approximately 97.9% of the equity of the Company.

 

The new Series D Stock is convertible into 7,295,744,128 shares of common stock and is redeemable October 19, 2014 at the option of the holders for $100 per share plus accrued and unpaid dividends of 10% per annum.

 

In addition to the exchange of debt and securities for the new common and preferred shares, Markham and Orogen established a 120-day, $5 million senior secured credit facility to fund working capital and capital expenditure requirements of the Company.  For extending the credit facility, the Company also issued to Markham and Orogen a total of 250,000 shares of Gasco common stock.

 

In late 2012 and early 2013, the Company received notices from the Exchange  notifying the Company that it did not satisfy certain continued listing standards set forth in the NYSE MKT LLC Company Guide (the “Company Guide”). Specifically, on December 6, 2012, the Company received a notice from the Exchange indicating that it did not satisfy the continued listing standards of the Exchange set forth in Section 1003(f)(v) of the Company Guide because the Company’s common stock had traded at a low

 

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price per share for a substantial period of time.  In the notice, the Exchange predicated the Company’s continued listing on the Exchange on the Company effecting a reverse stock split of its common stock by June 6, 2013. On January 11, 2013, the Company received a notice from the Exchange indicating that it did not satisfy the continued listing standards of the Exchange set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature. In order to maintain its listing, the Company was required to submit a plan of compliance (a “Plan”) addressing how it intended to regain compliance with Section 1003(a)(iv) of the Company Guide by June 30, 2013.  The Company submitted a Plan to the Exchange on February 11, 2013.  The Plan indicated that the Company intended to lower costs, rationalize assets, refocus its development program toward oil and liquids, especially in the Green River Formation, and continue its California program with the potential goal of expanding activity on the California acreage.  The Plan also discussed the fact that the Company was considering certain strategic alternatives, including debt restructuring and sales of assets.

 

On March 27, 2013, the Company received notice from the Exchange indicating that after a careful review of the Plan and publicly available information, the Exchange had determined that the Company had not made a reasonable demonstration of its ability to regain compliance with Section 1003(a)(iv) of the Company Guide by June 30, 2013 and that the Exchange intended to initiate delisting proceedings against the Company by filing a delisting application with the SEC pursuant to Section 1009(d) of the Company Guide.  The Company originally intended to appeal the Exchange’s determination, but subsequently determined not to proceed with such an appeal and notified the Exchange of its decision on April 23, 2013.  Accordingly, trading of the Company’s common stock on the Exchange was suspended at the opening of business on April 26, 2013 and the Exchange has delisted the Company’s common stock.  The Company’s common stock immediately became eligible to trade on the OTCQB Marketplace on April 26, 2013, and is currently trading thereon under the ticker symbol “GSXN.”

 

The Company may not achieve profitability from operations in the near future or at all and it may continue to experience significant losses.  The Company had net losses for the nine months ended September 30, 2013 and has had negative cash flow from operations for the year ended December 31, 2012, and at September 30, 2013 had an accumulated deficit of $252,556,384.

 

The Company also has firm commitment delivery obligations under its gas transportation and processing agreements.  If these commitments are not met, unless suspended pursuant to the terms of such agreements or waived, the Company may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments as discussed further in Note 9 — Gas Processing Agreements, herein.

 

Failure to generate sufficient operating cash flow or to obtain additional financing for the development of the Company’s properties could result in substantial dilution of its property interests or delay or cause indefinite postponement of further exploration and development of its prospects resulting in the possible loss of its properties. This has caused the Company to alter its business plans, and the Company may be required to further reduce its exploration and development plans.  For example, the Company did not allocate any amounts to its 2013 capital budget prior to the Restructuring Transactions.  In particular, the Company faces uncertainties relating to its ability to fund the level of capital expenditures required for oil and gas exploration and production activities. The Company intends to fund its anticipated cash requirements through February 2014 primarily through cash on hand and cash inflows from operations and from borrowings under its line of credit, although the Company cannot provide assurances that these cash flows will be sufficient to fund such requirements. If they are not, the Company’s ability to execute its operations will be significantly limited, and its liquidity and results of operations will be materially adversely affected.

 

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To continue as a going concern, the Company must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity.  The Company’s ability to do so will depend on numerous factors, some of which are beyond its control.  For example, the urgency of the Company’s liquidity situation may require it to pursue such a transaction at an inopportune time when the Company has little or no negotiating leverage.  Moreover, the Company’s ability to successfully implement, and the cost of, any such transaction will depend on numerous factors, including:

 

·                  demand and prices for natural gas and oil;

·                  general economic conditions;

·                  strength of the credit and capital markets;

·                  the Company’s ability to successfully execute its operational strategies, and its operating and financial performance;

·                  the Company’s ability to comply with its debt and equity instruments and to cure or obtain a waiver of any non-compliance;

·                  the Company’s stock price, and the ability of its common stock to remain traded on the OTCQB Marketplace;

·                  the Company’s ability to remain in compliance with its operational agreements, including its gas processing, gathering and transportation agreements;

·                  the Company’s counterparties refraining from exercising any remedies available as a result of the determination that the Company is insolvent or unable to perform in accordance with the contract;

·                  the Company’s ability to maintain relationships with its suppliers, customers, employees, stockholders and other third parties; and

·                  market uncertainty in connection with the Company’s ability to continue as a going concern as well as investor confidence in the Company.

 

If the Company is unable to generate sufficient operating cash flows or secure additional capital before February 2014, it will not have adequate liquidity to fund its operations and meet its obligations (including its debt payment obligations), the Company will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code.

 

A bankruptcy filing by or against the Company would subject its business and operations to various risks, including but not limited to, the following:

 

·                  a bankruptcy filing by or against the Company may adversely affect its business prospects, including its ability to continue to obtain and maintain the contracts necessary to operate its business on competitive terms;

·                  subject to the automatic stay and other applicable provisions of the Bankruptcy Code, a bankruptcy filing by or against the Company could cause a party to attempt to declare an additional event of default under the Indenture;

·                  subject to the automatic stay and other applicable provisions of the Bankruptcy Code, certain provisions in the Company’s operating agreements may be triggered such that  a party could attempt to assert that the Company is deemed to have resigned as operator or the agreements may be terminated by the other party;

·                  the Company may be unable to retain and motivate key executives and employees through the process of reorganization, and it may have difficulty attracting new employees;

·                  there can be no assurance as to the Company’s ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;

 

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·                  there can be no assurance that the Company will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and its creditors, equity holders and other parties in interest; and

·                  the value of the Company’s common stock could be reduced to zero.

 

In order to address the Company’s liquidity constraints the Company has embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan may be further revised in light of the Restructuring Transaction; however, the plan contemplates the Company, among other things:

 

·                  reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013 prior to the Restructuring Transactions;

·                  managing working capital;

·                  delaying certain drilling projects;

·                  pursuing farm-out and other similar types of transactions to fund working capital needs;

·                  evaluating its options for the divestiture of certain assets;

·                  investigating merger opportunities; and

·                  restructuring and reengineering the Company’s organization and processes to reduce operating costs and increase efficiency.

 

The Company cannot provide any assurances that it will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, the Company’s cash management strategy, if successful, may limit certain of its initiatives, including its ability to successfully execute its strategic alternatives.

 

NOTE 3 — 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 $0 and $8,807 of internal costs during the three and nine months ended September 30, 2013 and $0 and $11,520 during the three and nine months ended September 30, 2012, respectively.  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, therefore, the net income attributable to the outside working interest owners from such marketing activities of $60,402 and $175,535 was recorded as an adjustment to proved properties during the three and nine months ended September 30, 2013 and $37,896 and $69,700 was recorded as an adjustment to proved properties during the three and nine months ended September 30, 2012, 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 7 — Asset Sales, herein.

 

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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. The costs of unproved properties of $31,717,970 as of September 30, 2013, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. If a determination is made that acreage will be expiring or that the Company does not plan to develop some of the acreage that is no longer considered to be prospective, an impairment of the acreage is recorded by reclassifying the costs to the full cost pool. The value of these acres for the purpose of recording the impairment is estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by the Company. This per acre estimate is then applied to the acres that the Company does not plan to develop in order to calculate the impairment. During the nine months ended September 30, 2013, the Company reclassified approximately $796,000 of acreage costs in California and Utah into proved property. This acreage represents the value of leases that expired during the first nine months of 2013 or that the Company does not intend to renew in the future.

 

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 (i) 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 (ii) the cost of properties not being amortized, if any; plus (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (iv) 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 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 price during the 12-month period ended as of the last day of the period 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, June 30, 2012 and September 30, 2012, the 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012 and $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012. Therefore, impairment expense of $1,016,000 and $9,071,000 was recorded during the three and nine months ended September 30, 2012, respectively.  No impairment expense related to the Company’s oil and gas properties was recorded during the three and nine months ended September 30, 2013.

 

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Facilities and Equipment

 

The Company’s 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 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 $17,356 and $29,326 during the three and nine months ended September 30, 2013 and $22,359 and $14,551 during the three and nine months ended September 30, 2012, respectively.

 

Inventory

 

Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method. During the three and nine months ended September 30, 2013, the Company recorded impairment expense of $789,143 and $1,019,643, respectively, related to the decrease in the market value of its inventory.

 

Inventory Held for Sale

 

During the first nine months of 2013, the Company determined that it would not have a future need for some of its casing and tubing inventory. Consequently, in September 2013, the Company developed a formal plan to sell the inventory. The Company reviewed various options for selling this inventory and decided that selling this inventory at auction would be the best option based on its current financial position and the need for additional cash flow. The Company agreed to sell this inventory at auction in September and the inventory was sold in October for $323,500 less selling expenses of $16,175.

 

Commodity Derivatives

 

From time to time, the Company has used 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 historically decided not to use hedge accounting under the accounting guidance for commodity derivatives and therefore, the changes in fair value are recognized in earnings. See Note 8 — 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, “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 sheets with changes in their fair value reported in earnings. 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

 

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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.

 

As a result of the Restructuring Transactions, the Warrants became immediately puttable. The Company has a derivative instruments liability of $71,000 to cover the potential put of the Warrants.

 

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 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.

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Balance beginning of period

 

$

856,308

 

$

779,197

 

$

815,660

 

$

1,226,796

 

Liabilities incurred

 

 

 

2,338

 

 

Property dispositions

 

 

 

 

(493,178

)

Accretion expense

 

19,893

 

18,019

 

58,203

 

63,598

 

Balance end of period

 

$

876,201

 

$

797,216

 

$

876,201

 

$

797,216

 

 

See Note 7 — Asset Sales, herein, for discussion of property dispositions.

 

Revenue Recognition

 

The Company records revenues from the sale 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 September 30, 2013, the off-balance sheet arrangements and

 

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transactions that the Company had entered into included operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. See Note 9 — Gas Processing Agreements, herein, for additional discussion regarding certain gas transportation and processing agreements.

 

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 vested and unvested shares of restricted stock. Diluted net income (loss) per common share of stock is computed by dividing net income as adjusted for earnings allocated to participating securities 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 shares of common stock, (iii) outstanding shares of Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of common stock, and (iv) the Company’s outstanding 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 (the repurchases of shares 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, Warrants 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. Basic and diluted net loss per share was the same for the three and nine months ended September 30, 2013 and 2012.

 

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 September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Shares related to:

 

 

 

 

 

 

 

 

 

2015 Notes

 

75,280,000

 

75,280,000

 

75,280,000

 

75,280,000

 

Preferred Stock

 

30,344,173

 

30,344,173

 

30,344,173

 

30,344,173

 

Common stock options

 

6,217,647

 

9,815,468

 

6,217,647

 

9,815,468

 

Warrants

 

30,250,000

 

30,250,000

 

30,250,000

 

30,250,000

 

Unvested restricted common stock

 

204,000

 

425,500

 

204,000

 

425,500

 

 

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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

 

Reclassifications

 

Certain reclassifications have been made to prior years’ amounts to conform to the classifications used in the current year. Such reclassifications had no effect on the Company’s net loss for the periods presented.

 

NOTE 4 — RESTRUCTURING TRANSACTIONS

 

On October 17, 2013, Markham and  Orogen (collectively, the “Purchasers”), and the holders of  the 2015 Notes (see Note 6 - Convertible Senior Notes, herein), entered into certain Purchase and Sale Agreements (the “Note Purchase Agreements”) pursuant to which, among other things, the Purchasers acquired (i) $45,168,000 in aggregate outstanding principal amount of the Company’s 2015 Notes plus accrued interest of $2,495,022, representing 100% of the issued and outstanding 2015 Notes, (ii) 182,065 shares of the Company’s Series C Stock, representing 100% of the issued and outstanding Series C Stock, and (iii) 2,743,818 shares of common stock, par value $0.0001 per share from the holders of the 2015 Notes.

 

On October 18, 2013, in exchange for the issuance of 250,000 shares of common stock by the Company to the Purchasers, the Company and the Purchasers entered into a certain Credit Agreement (the “Credit Agreement”), pursuant to which, among other things, the Purchasers extended credit to the Company in the maximum principal amount of $5,000,000 in the form of a revolving credit facility to fund working capital and capital expenditure requirements of the Company (the “Credit Facility”). See Note 5 — Credit Facility, herein for further discussion.

 

On October 18, 2013, following the consummation of the transactions contemplated by the Credit Agreement, the Company and Purchasers entered into a Securities Purchase Agreement, pursuant to which, in exchange for the Purchasers transferring the 2015 Notes, accrued interest and the Series C Stock to the Company, the Company issued to the Purchasers an aggregate of (i) 393,550,372 shares of common stock, and (ii) 50,000 shares of Series D Stock of the Company. The 2015 Notes, accrued interest and the Series C Stock were cancelled following their acquisition by the Company.

 

Each share of Series D Stock is convertible at the option of the Purchasers into 145,914.88 shares of common stock, or an aggregate of 7,295,744,128 shares of common stock. The Series D Stock also ranks senior to all existing preferred stock and common stock of the Company with respect to dividend rights, redemption rights and rights upon liquidation. From and after the date of the issuance of any shares of Series D Stock, dividends accrue on each share at the rate of 10% per annum of the Series D Stock’s stated value of $100 per share, plus accrued but unpaid dividends, compounded quarterly. If the Company is liquidated and the assets and funds available for distribution among the holders of Series D Stock are insufficient to permit the payment in full of the liquidation value of all of the outstanding Series D Stock, then the entire

 

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assets and funds of the Company will be distributed ratably in respect of the holders of Series D Stock. Beginning one year and one day after the original date of issuance, the Purchasers can require that the Company redeem the outstanding shares of Series D Stock at a redemption price equal to the stated value of $100 per share, plus accrued and unpaid dividends. The shares of Series D Stock are entitled to vote on an as-converted basis with the holders of the common stock on any matter presented to the holders of the common stock for their action or consideration. The Series D Stock is subject to anti-dilution protection as well as certain protective provisions.

 

Because the Company does not currently have a sufficient number of authorized and unreserved common shares to permit the full conversion of the Series D Stock, the Board of Directors of the Company has approved and adopted an amendment to its charter to increase the number of Gasco common shares and has recommended to the Purchasers that they approve the charter amendment by written consent.  The written consent approving the charter amendment was subsequently executed by the Purchasers on October 23, 2013, but the charter amendment is not yet effective pending the completion of required SEC filings.

 

The Company will record the impact of the Restructuring Transactions in its consolidated financial statements for the year ended December 31, 2013.

 

NOTE 5 — CREDIT FACILITY

 

In connection with the Restructuring Transactions and pursuant to the Credit Agreement, the Purchasers established the Credit Facility for the Company.  The Credit Facility bears interest at a fixed annual rate of 8% and becomes due on February 18, 2014.  The Credit Facility is secured by substantially all of the proved oil and gas assets and all personal property of the Company and its subsidiaries and by guarantees of each of the Company’s subsidiaries.  The Credit Facility contains certain customary restrictive covenants and also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross defaults, bankruptcy and material judgments.

 

For extending the Credit Facility, the Company also issued a total of 250,000 shares of common stock to the Purchasers.

 

On October 18, 2013, the Company borrowed $2,500,000 under the Credit Facility, which was used for general corporate purposes, leaving the Company with $2,500,000 of credit availability under the Credit Facility, subject to the terms and conditions thereof.

 

NOTE 6 - CONVERTIBLE SENIOR NOTES

 

As of September 30, 2013, the Company had $45,168,000 aggregate principal amount of 2015 Notes outstanding that were due October 2015.

 

The 2015 Notes bore interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  The Company elected not to make the $1,242,120 semi-annual interest payments due on April 5, and October 5, 2013 on its outstanding 2015 Notes and therefore an event of default occurred under the Indenture requiring the Company to pay interest on overdue interest payments at a rate of 7.5% per annum. As a result of the event of default, the 2015 Notes were classified as a current liability in the accompanying unaudited condensed consolidated financial statements.

 

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

 

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30, 2013 and December 31, 2012 was $14,731,680 and $18,530,539, respectively.

 

As of the date of the Restructuring Transactions, total principal and accumulated interest on the 2015 Notes (including default interest) equaled $47,795,256. The 2015 Notes and accrued interest were cancelled on October 18, 2013. See Note 4 - Restructuring Transactions, herein for further discussion.

 

NOTE 7 — ASSET SALES

 

Uinta Basin Joint Venture

 

On March 22, 2012, the Company closed a 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, which was repaid in full during the second quarter of 2012, 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.

 

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 behalf of the Company, and the Company has agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million. If the Company is not able to pay its share of the above costs, it may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the Operating Committee (as defined below), the right to transfer its interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion 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 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”).

 

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

 

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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. 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.  However, to the extent that Gasco Production Company, as operator under these agreements, becomes insolvent, bankrupt or is placed into receivership, it will be deemed to have resigned as operator or Wapiti may have a termination right.  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 consists of two members from each of the Company and Wapiti, with the members appointed by each party having an aggregate 50% vote.

 

The Development Agreement contains transfer restrictions on each of the Company’s 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 the Company or Wapiti upon six months’ advance notice.

 

Due primarily to permitting delays in obtaining various governmental approvals, the Company did not drill any natural gas wells in Utah from the closing of the Uinta Basin Transaction through the end of the third quarter of 2013.

 

The Company used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under its prior revolving credit facility.

 

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 have significantly altered 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, 2012, 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, 2012. The pro forma results for the three and nine months ended September 30, 2013 and the three months ended September 30, 2012 were the same as the actual results and are not included in the table below.

 

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Nine Months Ended

 

 

 

September 30, 2012

 

 

 

 

 

Revenue as reported

 

$

6,592,765

 

Less: revenue from the Uinta Basin Transaction

 

1,206,145

 

Pro forma revenue

 

$

5,386,620

 

 

 

 

 

Net loss as reported

 

$

(13,380,613

)

Less: operating loss resulting from the Uinta Basin Transaction

 

(2,390,235

)

Pro forma net loss

 

$

(10,990,378

)

 

 

 

 

Net loss per share — basic and diluted as reported

 

$

(0.08

)

Less net loss per share — from the Uinta Basin Transaction

 

(0.01

)

Pro forma net loss income per share — basic and diluted

 

$

(0.07

)

 

NOTE 8 — DERIVATIVES

 

From time to time, 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. During 2013, the Company did not have any commodity derivative contracts, and during the first nine months of 2012, the Company’s natural gas derivative instruments consisted of one costless collar agreement for production from January 1, 2012 through December 31, 2012. During June 2012, the Company monetized this contract for net proceeds of $677,868. Prior to the monetization, the costless collar contained a fixed floor price (purchase put) and ceiling price (written call). The Company received the difference between the published index price and the floor price if the index price was below the floor price. The Company paid the difference between the ceiling price and the index price only if the index price was above the ceiling price. If the index price was between the ceiling and the floor prices, no amounts were 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 unaudited condensed consolidated balance sheets:

 

 

 

Location on
Consolidated

 

Fair Value at

 

 

 

Balance Sheets

 

September 30, 2013

 

December 31, 2012

 

 

 

 

 

 

 

 

 

Warrant derivatives

 

Noncurrent liabilities

 

$

71,000

 

$

907,500

 

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2013 and 2012.

 

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Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Realized gains on commodity instruments

 

$

 

$

 

$

 

$

1,255,948

 

Change in fair value of commodity instruments

 

 

 

 

(865,358

)

Change in fair value of warrant derivatives

 

104,000

 

720,000

 

836,500

 

2,117,500

 

Total realized and unrealized gains recorded

 

$

104,000

 

$

720,000

 

$

836,500

 

$

2,508,090

 

 

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

 

NOTE 9 — GAS PROCESSING AGREEMENTS

 

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 constructed.

 

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 that was built and placed in service on February 7, 2013. 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.

 

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.  Under the agreement, the Company committed to deliver, on average, at least 90% of its contracted cryogenic capacity of 25,000 Mcf/d (the “Minimum Daily Quantity”) during each monthly accounting period. Following the first twelve monthly accounting periods, Chipeta may determine whether the Company failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period.  If the Company delivered less than the quantity it committed to deliver, it would be required to pay a deficiency payment equal to the contracted cryogenic processing fee multiplied by the deficient quantity. In addition, to the extent that Chipeta has reasonable grounds for uncertainty regarding the performance of our obligations under the agreement, including a material change in the Company’s creditworthiness, Chipeta may sell the Company’s natural gas and apply amounts received against any amounts owed to Chipeta, set off any amount owed to the Company against amounts owed to Chipeta or cease processing our natural gas until the Company’s account is current, with interest.  Chipeta may also demand adequate assurance of performance from the Company, which may be in the form of a standby irrevocable letter of credit, prepayment or performance bond or guaranty. The Company has not received notification from Chipeta that it intends to pursue any of these options.

 

Historically, the Company’s natural gas production had been gathered and processed by Monarch Natural Gas, LLC (“Monarch”) pursuant to the Gas Gathering and Processing Agreement, effective March 1, 2010, between Monarch and the Company. On March 22, 2012, the Company entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch in which Monarch agreed to, among other things, (a) release and waive its

 

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rights to process the first 50,000 MMBtu/day of the Company’s 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 the Company’s reserves in excess of the Excluded Production.  The Excluded Production may be reduced if the Company fails to meet certain drilling investment targets.  The Company is committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and, unless suspended pursuant to the terms of the Amended and Restated Monarch Agreement or waived, it is obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the Amended and Restated Monarch Agreement.

 

The Company has also entered into the Questar Wet Line Agreement, dated September 20, 2011, with Questar Pipeline Company (“QPC”), pursuant to which the Company agreed to enter into separate transportation services agreements for firm transportation services. The Company is currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.

 

These contracts expire at various dates through 2023 and, unless suspended pursuant to the terms of the contracts or waived by the counterparty, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. These amounts are owed regardless of whether the Company delivers any natural gas quantities to the applicable parties. As described in Note 2 — Going Concern, herein, there is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations. If the Company is unable to fund additional drilling projects, and based on its September 30, 2013 reserve estimates, assuming no future drilling and constant gas prices, it estimates that it could have a possible future aggregate minimum production shortfall of approximately 41,000 MMcf valued at approximately $28 million on an undiscounted gross basis. The Company accrued $373,000 in shortfall commitments related to the nine months ended September 30, 2013.

 

The Company is considering several alternatives to mitigate the estimated production shortfall such as the sale of its firm commitment positions, seeking relief from the firm commitments because of legal delays in the area that prevented the Company from obtaining various governmental approvals and the purchase of production quantities to meet its minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce the possible shortfalls. However, there is no assurance that the Company will be successful in accomplishing these actions should there be a shortfall. Accordingly, the Company has not accrued the future possible obligation as of September 30, 2013 as it is not probable or reasonably estimable.

 

NOTE 10 — STOCK-BASED COMPENSATION

 

As of September 30, 2013, the Company has outstanding common stock options 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; however, the Company assumes no forfeitures for employee awards based on its historical forfeiture experience. During the year ended December 31, 2012 and through January 2013, the Company also had outstanding SARs which were accounted for as liability-based awards and accordingly, the Company recognized 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.

 

During the nine months ended September 30, 2012, the Company accounted for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock

 

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compensation related to unvested stock options issued to non-employees was recalculated at the end of each reporting period based upon the fair value on that date. There were no stock compensation arrangements with non-employees during the first nine months of 2013.

 

During the three and nine months ended September 30, 2013 and 2012, the Company recognized stock-based compensation expense as follows:

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Employee compensation

 

$

39,399

 

$

79,182

 

$

139,655

 

$

216,053

 

Consultant compensation

 

 

(191

)

 

(213

)

Total stock-based compensation

 

39,399

 

78,991

 

139,655

 

215,840

 

Less: consultant compensation expense capitalized as proved property

 

 

(95

)

 

(106

)

Stock-based compensation expense

 

$

39,399

 

$

79,086

 

$

139,655

 

$

215,947

 

 

Stock Options

 

The following table summarizes the stock option activity in the Company’s equity incentive plans from January 1, 2013 through September 30, 2013:

 

 

 

Shares Underlying
Stock Options

 

Weighted-Average
Exercise Price

 

Outstanding at January 1, 2013

 

9,506,943

 

$

1.04

 

Granted

 

 

 

Exercised

 

 

 

Forfeited

 

(461,474

)

$

0.12

 

Cancelled

 

(2,827,822

)

$

0.59

 

Outstanding at September 30, 2013

 

6,217,647

 

$

1.09

 

Exercisable at September 30, 2013

 

5,478,402

 

$

1.21

 

 

The following table summarizes information related to the outstanding and vested options as of September 30, 2013:

 

 

 

Outstanding Options

 

Vested Options

 

Number of shares

 

6,217,647

 

5,478,402

 

Weighted-Average Remaining Contractual Life

 

2 Years

 

2 years

 

Weighted-Average Exercise Price

 

$1.09

 

$1.21

 

Aggregate intrinsic value

 

 

 

 

The aggregate intrinsic value in the table above represents the total pretax intrinsic value based on the fair value of the Company’s common stock of $0.02 as of September 30, 2013, 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.

 

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As of September 30, 2013, there is $79,470 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 approximately 2 years.

 

Restricted Stock

 

The following table summarizes the restricted stock activity from January 1, 2013 through September 30, 2013:

 

 

 

Restricted
Stock

 

Weighted-Average
Grant Date
Fair Value

 

Outstanding at January 1, 2013

 

336,000

 

$

0.22

 

Granted

 

 

 

Vested

 

(48,095

)

$

0.18

 

Forfeited

 

(92,000

)

$

0.22

 

Outstanding at September 30, 2013

 

195,905

 

$

0.24

 

 

As of September 30, 2013, there is $25,530 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of approximately 2 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. The 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 common stock on the date of exercise, over (ii) $0.25, which was 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 no cash payment was made.

 

Effective February 28, 2012, the Company granted another SARs award related to a total of 1,000,000 shares of its common stock to its non-employee directors.  As of December 31, 2012, the liability for the SARs was approximately zero. The SARs provided 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 was  less, over (ii) $0.30, which was 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 SARs vested on January 31, 2013 and were automatically exercised on February 1, 2013. 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 no cash payment was made.

 

NOTE 11 — 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

 

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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 September 30, 2013 and December 31, 2012 by level within the fair value hierarchy:

 

 

 

Fair Value Measurements Using

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

September 30, 2013

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Warrant derivatives

 

$

 

$

 

$

71,000

 

$

71,000

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Warrant derivatives

 

$

 

$

 

$

907,500

 

$

907,500

 

 

As of September 30, 2013, 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 Chief Accounting Officer and are approved by the Chief Executive Officer. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the Chief Accounting Officer and the Chief Executive Officer 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

 

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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 September 30, 2013:

 

(i)             the warrant derivative liability would decrease to zero if the trading price of Gasco’s common stock was reduced to zero, and would increase by approximately $1.4 million for a $0.10 increase in the trading price of its common stock; and

(ii)          the warrant derivative liability would increase by $33,000 with a 10% increase and would decrease by $27,000 with a 10% decrease in the volatility rate.

 

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

 

 

 

Number of

Warrants

 

Exercise
Price

 

Weighted
Average
Remaining

Contractual Life

 

Warrants outstanding as of 12/31/12

 

30,250,000

 

$

0.35

 

40 months

 

Warrants issued

 

 

 

 

 

Warrants outstanding as of 9/30/13

 

30,250,000

 

$

0.35

 

33 months

 

 

The significant assumptions used in the valuation of the warrant derivative liability as of September 30, 2013 are as follows:

 

Exercise price

 

$0.35 per share

Stock price

 

$0.02 per share

Volatility

 

105%

Remaining Term of Warrants

 

32 - 34 months

Risk-free interest rate

 

0.5% - 1%

 

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:

 

 

 

For the Three Months
Ended
September 30,

 

For the Nine Months

Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Balance as of beginning of period

 

$

(175,000

)

$

(2,837,500

)

$

(907,500

)

$

(4,235,000

)

Total gains (realized or unrealized):

 

 

 

 

 

 

 

 

 

Included in earnings

 

104,000

 

720,000

 

836,500

 

2,117,500

 

Included in other comprehensive income

 

 

 

 

 

Issuances

 

 

 

 

 

Settlements

 

 

 

 

 

Transfers in and out of Level 3

 

 

 

 

 

Balance as of September 30,

 

$

(71,000

)

$

(2,117,500

)

$

(71,000

)

$

(2,117,500

)

Change in unrealized gains included in earnings relating to instruments still held as of September 30,

 

$

104,000

 

$

2,117,500

 

$

(71,000

)

$

2,117,500

 

 

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The carrying amounts of cash and cash equivalents, accounts 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 $14,125,000 and $28,833,000 as of September 30, 2013 and December 31, 2012, respectively, was determined using trading prices as of September 30, 2013 and the income valuation technique and option pricing model as of December 31, 2012. This valuation is classified as a Level 3 in the fair value hierarchy as it relies primarily on unobservable pricing inputs.

 

NOTE 12 - STATEMENTS OF CASH FLOWS

 

During the nine months ended September 30, 2013, the Company’s non-cash investing and financing activities consisted of the following transaction:

 

·                  Additions to oil and gas properties included in accounts payable of $518,000.

 

During the nine months ended September 30, 2012, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

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

 

·                  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.

 

Cash paid for interest during the nine months ended September 30, 2012 was $1,353,761. There was no cash paid for interest during the nine months ended September 30, 2013 and no cash was paid for income taxes during the nine months ended September 30, 2013 and 2012.

 

NOTE 13 — LEGAL PROCEEDINGS

 

The Company is party to various legal proceedings arising out of the normal course of business.  The most significant legal proceedings to which the Company is subject are 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 these proceedings 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 (the “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: (i) once when it constructed an access road to a future well location in either 2004 or 2005 and (ii) 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 Company disagrees with some of the factual contentions in the compliance order, and it has had a number of discussions with the EPA concerning the order.  However, it has been unable to negotiate a successful resolution of the alleged violations with the

 

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EPA, and as a result, it filed a lawsuit in federal district court in the District of Colorado on June 25, 2012.  The lawsuit seeks judicial review of the compliance order, specifically review of the EPA’s contention that the affected areas are wetlands, or if they are wetlands, whether they are wetlands that are subject to federal regulatory jurisdiction under the Clean Water Act.  On September 5, 2012, the EPA, represented by the U.S. Department of Justice (“DOJ”), answered, and the United States separately counterclaimed for an injunction seeking substantially the same relief that the EPA seeks in the compliance order but also requested civil penalties for each day of alleged discharges of fill material and each day of alleged violation of the compliance order.  The Company has answered the EPA’s counterclaim.  In late January 2013, pursuant to a Scheduling Order before the court, the Company submitted a brief in support of its claims under the original suit filed in June 2012.  At this point, it appears to us that our original claim and the DOJ’s counterclaim will be tried concurrently.

 

NEPA Suit

 

In June 2012, the U.S. Bureau of Land Management (“BLM”) signed and issued a Record of Decision (“ROD”) on the Environmental Impact Statement (“EIS”) that authorizes the development of the Company’s Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah.  This field includes the Company’s core Riverbend Project.  However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance (“SUWA”), filed a suit against the BLM, challenging the ROD issued by that agency.  In its complaint, SUWA alleges that the BLM failed to comply with the requirements of the National Environmental Policy Act and its implementing regulations.  SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for the Company to proceed with its planned project. Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to the Company.

 

Hat Creek Settlement

 

In February 2013, the Company settled a claim with one of its working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that was operated by the Company and owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by the Company in violation of the joint operating agreement, and that Hat Creek’s working interest in the well was impaired as a result.  Hat Creek sought damages of not less than $200,000, and the Company sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs.  The Company settled this claim for $307,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $147,000 in accounts receivable owed to the Company by Hat Creek. In addition, the settlement provides that the Company will receive Hat Creek’s ownership interest in the well.  The final settlement was accrued as of December 31, 2012.

 

NOTE 14 — 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 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

 

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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.

 

NOTE 15 — SUBSEQUENT EVENTS

 

See Note 3 – Significant Accounting Policies - Inventory Held for Sale, herein for subsequent events.

 

See Note 4 – Restructuring Transactions, herein for subsequent events.

 

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

 

Forward-Looking Statements

 

Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” for a discussion of factors that could affect the outcome of forward-looking statements used herein.

 

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 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

 

Outlook

 

Due to the extended decline in the natural gas market and low natural gas prices in recent years caused primarily by excess production, we have not been able to recover its exploration and development costs as anticipated.  As such, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund its ongoing operations, and we currently anticipate that cash on hand, available cash under the credit facility described below and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital through February 2014. This expectation has been revised from our previous estimate included in the Form 10-Q for the quarter ended June 30, 2013 due to the completion of the October 2013 transaction discussed below, the implementation of cost savings measures and cash management strategies. This estimate is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the end of February 2014.   As a result of these factors, there is substantial doubt about our ability to continue as a going concern.

 

Restructuring Transactions

 

We have been seeking to restructure or refinance our debt or sell assets to improve our liquidity position since mid-year 2012. During this period, we have operated without a credit facility, have been delisted from the NYSE MKT LLC (the “Exchange”), and have defaulted under the 2015 Notes.

 

The Company and Stephens Inc., our financial advisor, conducted a process to evaluate various strategic alternatives.  The restructuring agreements resulting from this process involve an investment in the Company by Markham LLC (“Markham”) and Orogen Energy, Inc. (“Orogen”). On October 17, 2013, these investors acquired the $45,168,000 aggregate principal amount of our 2015 Notes and accrued interest thereon, all 182,065 outstanding Series C convertible preferred shares (“Series C Stock”) and common shares owned by the holders of the 2015 Notes. Then on October 18, 2013, the investors exchanged the 2015 Notes, accrued interest and Series C Stock for 393,550,372 shares of the Company’s

 

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Table of Contents

 

common stock and 50,000 shares of the newly-created Series D convertible preferred stock (“Series D Stock”) (the “Restructuring Transactions”). As a result of the Restructuring Transactions, the new investors now have fully-diluted control of approximately 97.9% of the equity of the Company. In addition, the Company has a derivative instruments  liability of $71,000 recorded, which covers the potential put of Warrants of the Company described in Item 3 - “Quantitative and Qualitative Disclosures about Market Risk - Warrant Derivative Risk.”

 

The new Series D Stock is convertible into 7,295,744,128 shares of common stock and is redeemable October 19, 2014 at the option of the holders for $100 per share plus accrued and unpaid dividends of 10% per annum.

 

Because we do not currently have a sufficient number of authorized and unreserved common shares to permit the full conversion of the Series D Stock, our Board of Directors has approved and adopted an amendment to its charter to increase the number of common shares and has recommended to the stockholders that they approve the charter amendment by written consent. The written consent approving the charter amendment was subsequently executed by Markham and Orogen on October 23, 2013, but the charter amendment is not yet effective pending the completion of required SEC filings.

 

In addition to the exchange of debt and securities for the new common and preferred shares, Markham and Orogen have established a 120-day, $5 million senior secured credit facility to fund our working capital and capital expenditure requirements.  For extending the credit facility, we also issued to Markham and Orogen a total of 250,000 shares of Gasco common stock.

 

Following the closing of the Restructuring Transactions, the size of its Board of Directors was set at three members effective immediately and accepted the resignations of Richard J. Burgess, Charles B. Crowell, Steven D. Furbush and John A. Schmit as directors.  Richard S. Langdon remains a director and interim President and Chief Executive Officer of the Company. G. Wade Stubblefield was appointed to the Board of Directors of the Company upon the closing and the Company intends to add L. Edward Parker as a director upon compliance with Section 14(f) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and making required SEC filings.

 

NYSE MKT LLC Delisting

 

On March 27, 2013, we received notice from the Exchange indicating that after a careful review of the plan that we submitted to regain compliance with the Exchange’s continued listing standards and publicly available information, the Exchange had determined that we had not made a reasonable demonstration of our ability to regain compliance with the Exchange’s continued listing standards and that the Exchange intended to initiate delisting proceedings against us by filing a delisting application with the SEC.  We originally intended to appeal the Exchange’s determination, but subsequently determined not to proceed with such an appeal and notified the Exchange of our decision on April 23, 2013.  Accordingly, trading of our common stock on the Exchange was suspended at the opening of business on April 26, 2013 and the Exchange has delisted our common stock.  Our common stock immediately became eligible to trade on the OTCQB Marketplace on April 26, 2013, and is currently trading thereon under the ticker symbol “GSXN.”

 

Litigation Settlement

 

In February 2013, we settled a claim with one of our working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that we operated and was owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by us in violation of the joint operating agreement, and that Hat Creek’s

 

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working interest in the well was impaired as a result.  Hat Creek sought damages of not less than $200,000, and we sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs.  We settled this claim for $307,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $147,000 in accounts receivable owed to the Company by Hat Creek. In addition, the settlement provides that we will receive Hat Creek’s ownership interest in the well.  The final settlement was accrued as of December 31, 2012.

 

Green River Horizontal Well

 

During the first nine months of 2013, we participated in an outside-operated horizontal well (7.14% working interest/6.07% net revenue interest) that successfully tested productive potential of the oil-prone basal Uteland Butte member of the Green River Formation in the Uinta Basin.  The well reached total depth in 21 days with a 4,300 foot lateral length (9,772 feet total measured depth).  The well had an initial 24-hour gross production rate of 221 barrels of oil equivalent per day (BOE/d) (13.4 BOE/d net) and has gross cumulative production of 4,011 BOE (243 BOE net) in the first 21 days that it has been online (191 BOE/d gross average).  The well had cumulative gross production of 842 thousand cubic feet of natural gas in the 21-day period.  It is still too early in the life of the well to estimate ultimate recovery.

 

Given the initial success of this Green River test well, we believe that we have approximately 70 gross potential horizontal locations or about 150 gross vertical basal Uteland Butte member oil well locations in our Riverbend Project leasehold.  Horizontal location estimates are based upon 160-acre spacing in which we have the full 160-acre position.  The vertical location estimate includes acreage in which we do not have the full 160-acre position.

 

California Project — Antelope Valley Trend

 

Our partner in the Antelope Valley Trend is currently permitting three locations.  We will be carried for a 20% working interest in the first earning well.  Based on current permit processing, it is anticipated that the well is scheduled to be spud by the fourth quarter of 2013.

 

California Project — Willow Springs

 

Our partner in the Willow Springs Prospect continues to reprocess and work their 3-D seismic data.  Due to the amount of time required to perform this work properly, they requested an extension on their optional second well drilling commitment date.  The new extension date of November 13, 2013 was granted in June, 2013 and our partner will pay our share of the lease rentals during this period.

 

California Project — SW Cymric

 

As part of the Willow Springs second option well extension date discussions, we asked our partner to change the SW Symric Prospect well test from being an optional commitment to a firm well commitment.  Our partner agreed to this change.  The firm well test deadline is January 18, 2014.

 

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Inventory Held for Sale

 

During the first nine months of 2013, we determined that we would not have a future need for some of our casing and tubing inventory. Consequently, in September 2013, we developed a formal plan to sell the inventory. We reviewed various options for selling this inventory and decided that selling this inventory at auction would be the best option based on our current financial position and the need for additional cash flow. We agreed to sell this inventory at auction in September and the inventory was sold in October for $323,500 less selling expenses of $16,175.

 

Gas Processing Agreements

 

On September 21, 2011, we entered into a Gas Processing Agreement (the “Chipeta Processing Agreement”) with Chipeta Processing LLC (“Chipeta”) pursuant to which we dedicated certain of our natural gas production from our 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 constructed.

 

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 that was built and placed in service on February 7, 2013. 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.

 

Pursuant to the Chipeta Processing Agreement, we reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  We 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.  Under the agreement, we committed to deliver, on average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d (the “Minimum Daily Quantity”) during each monthly accounting period. Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period.  If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the contracted cryogenic processing fee multiplied by the deficient quantity. In addition, to the extent that Chipeta has reasonable grounds for uncertainty regarding the performance of our obligations under the agreement, including a material change in our creditworthiness, Chipeta may sell our natural gas and apply amounts received against any amounts we owe to Chipeta, set off any amount owed to us against amounts owed to Chipeta or cease processing our natural gas until our account is current, with interest.  Chipeta may also demand adequate assurance of performance from us, which may be in the form of a standby irrevocable letter of credit, prepayment or performance bond or guaranty. We have not received notification from Chipeta that it intends to pursue any of these options.

 

Historically, our natural gas production had been gathered and processed by Monarch Natural Gas, LLC (“Monarch”) pursuant to the Gas Gathering and Processing Agreement, effective March 1, 2010, with Monarch. On March 22, 2012, we entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch in which 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.  We are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and, unless suspended pursuant to the terms of the Amended and Restated

 

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Monarch Agreement or waived, are obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the Amended and Restated Monarch Agreement.

 

We have also entered into the Questar Wet Line Agreement, dated September 20, 2011, with Questar Pipeline Company (“QPC”), pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.

 

These contracts expire at various dates through 2023 and, unless suspended pursuant to the terms of the contracts or waived by the counterparty, we will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties. As discussed above, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations. If we are unable to fund additional drilling projects, and based on our June 30, 2013 reserve estimates, assuming no future drilling and constant gas prices, we estimate that we could have a possible aggregate minimum production shortfall of approximately 41,000 MMcf valued at approximately $28 million on an undiscounted gross basis. Shortfall commitments of $373,000 during the nine months ended September 30, 2013 were accrued in the accompanying unaudited condensed consolidated financial statements.

 

We are considering several alternatives to mitigate the estimated production shortfall such as the sale of our firm commitment positions, seeking relief from the firm commitments because of legal delays in the area that prevented us from obtaining various governmental approvals and the purchase of production quantities to meet our minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce the possible shortfalls. However, there is no assurance that we will be successful in accomplishing these actions should there be a shortfall. Accordingly, we have not accrued the possible future obligation as of September 30, 2013 as it is not probable or reasonably estimable.

 

Oil and Gas Production Summary

 

The following table presents our production and price information during the three and nine months ended September 30, 2013 and 2012. The Mcfe calculations assume a conversion of six Mcf for each Bbl of oil.

 

 

 

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

448,095

 

516,268

 

1,402,018

 

1,910,977

 

Average sales price per Mcf

 

$

4.40

 

$

2.81

 

$

4.13

 

$

2.63

 

 

 

 

 

 

 

 

 

 

 

Oil production (Bbl)

 

5,882

 

4,304

 

17,131

 

18,398

 

Average sales price per Bbl

 

$

89.57

 

$

83.14

 

$

84.02

 

$

84.84

 

 

 

 

 

 

 

 

 

 

 

Production (Mcfe)

 

483,387

 

542,092

 

1,504,804

 

2,021,365

 

 

Our equivalent oil and gas production decreased by 11% and 26% during the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012. The decrease in production

 

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reflects normal production declines and the conveyance of a 50% interest in certain of our Uinta Basin properties to our joint venture partner as part of the joint venture transaction which closed on March 22, 2012 (the “Uinta Basin Transaction”).  See Note 7 — Asset Sales of the accompanying unaudited condensed consolidated financial statements.

 

Liquidity and Capital Resources

 

General

 

We have historically generated cash from the sale of oil and natural gas, and have relied in the past primarily on the issuance of equity, borrowings under our prior 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 nine months ended September 30, 2013, we incurred a net loss of $7,748,228 and had an accumulated deficit of $252,556,384.

 

The unaudited condensed consolidated financial statements included in this Form 10-Q have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements.  As such, the unaudited condensed consolidated financial statements  included in this Form 10-Q do not include any adjustments relating to the recoverability and classification of assets, carrying amounts, or the amount and classification of liabilities that may result should we be unable to continue as a going concern.

 

For a description of the Restructuring Transactions, see “Recent Developments - Restructuring Transactions” above.We also have firm commitment delivery obligations under our gas transportation and processing agreements.  If these commitments are not met, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments as discussed further above under “Gas Processing Agreements.”

 

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 prospects resulting in the possible loss of our properties. This has caused us to alter our business plans, and we may be required to further reduce our exploration and development plans.  For example, we have not allocated any amounts to our 2013 capital budget.  In particular, we face uncertainties relating to our ability to fund the level of capital expenditures required for oil and gas exploration and production activities. We intend to fund our anticipated cash requirements through the end of  February 2014 primarily through borrowings under our Credit Facility, cash on hand and cash flows from operations, although we cannot provide assurances that cash on hand and cash flows from operations will be sufficient to fund such requirements. If they are not, our ability to execute our operations will be significantly limited, and our liquidity and results of operations will be materially adversely affected.

 

To continue as a going concern, we must generate sufficient operating cash flows, secure additional capital, refinancing or other transaction to provide us with additional liquidity.  Our ability to do so will depend on numerous factors, some of which are beyond our control.  For example, the urgency of our liquidity situation may require us to pursue such a transaction at an inopportune time when we have little or no negotiating leverage.  Moreover, our ability to successfully implement, and the cost of, any such transaction will depend on numerous factors, including:

 

·                  demand and prices for natural gas and oil;

·                  general economic conditions;

 

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·                  strength of the credit and capital markets;

·                  our ability to successfully execute our operational strategies, and our operating and financial performance;

·                  our ability to comply with our debt and equity instruments and to cure or obtain a waiver of any non-compliance;

·                  our stock price, and the ability of our common stock to remain traded on the OTCQB Marketplace;

·                  our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;

·                  our counterparties refraining from exercising any remedies available as a result of the determination that we are insolvent or unable to perform in accordance with the contract;

·                  our ability to maintain relationships with our suppliers, customers, employees, stockholders and other third parties; and

·                  market uncertainty in connection with our ability to continue as a going concern as well as investor confidence in us.

 

If we are unable to generate sufficient operating cash flows, secure additional capital before the end of February 2014, we will not have adequate liquidity to fund our operations and meet our obligations (including our debt payment obligations), we will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code.

 

A bankruptcy filing by or against us would subject our business and operations to various risks, including but not limited to, the following:

 

·                  a bankruptcy filing by or against us may adversely affect our business prospects, including our ability to continue to obtain and maintain the contracts necessary to operate our business on competitive terms;

·                  subject to the automatic stay and other applicable provisions of the Bankruptcy Code, a bankruptcy filing by or against us could cause a party to attempt to declare an additional event of default under the Indenture;

·                  subject to the automatic stay and other applicable provisions of the Bankruptcy Code, certain provisions in our operating agreements may be triggered such that a party could attempt to assert that the Company is deemed to have resigned as operator or the agreements may be terminated by the other party;

·                  we may be unable to retain and motivate key executives and employees through the process of reorganization, and we may have difficulty attracting new employees;

·                  there can be no assurance as to our ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;

·                  there can be no assurance that we will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and our creditors, equity holders and other parties in interest; and

·                  the value of our common stock could be reduced to zero.

 

In order to address our liquidity constraints and in addition to our ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity, we have embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates us, among other things:

 

·                  reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013 prior to the Restructuring Transactions;

 

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·                  managing working capital;

·                  delaying certain drilling projects;

·                  pursuing farm-out and other similar types of transactions to fund working capital needs;

·                  evaluating our options for the divestiture of certain assets;

·                  investigating merger opportunities; and

·                  restructuring and reengineering our organization and processes to reduce operating costs and increase efficiency.

 

We cannot provide any assurances that we will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, our cash management strategy, if successful, may limit certain of our initiatives, including our ability to successfully execute our strategic alternatives.

 

Sources and Uses of Funds

 

The following table summarizes our sources and uses of cash for each of the nine months ended September 30, 2013 and 2012.

 

 

 

For the Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Net cash provided by (used in) operations

 

$

351,000

 

$

(2,245,533

)

Net cash (used in) provided by investing activities

 

(1,280,652

)

14,413,691

 

Net cash used in financing activities

 

 

(8,544,969

)

Net (decrease) increase in cash

 

(929,652

)

3,623,189

 

 

Net cash provided by (used in) operations increased by $2,596,533 for the nine months ended September 30, 2013 compared to the same period in 2012. The increase in cash provided by operations was primarily due to an increase in working capital changes, a reduction in workover expenses during 2013 as a result of fewer projects partially offset by lower oil and gas revenue and higher transportation and processing costs during the first nine months of 2013.

 

Our investing activities during the first nine months of 2013 and 2012 included our development and exploration activities. The investing activity during the first nine months of 2012 also included the sales proceeds from the Uinta Basin Transaction (see Note 7 — Asset Sales of the accompanying unaudited condensed consolidated financial statements), cash paid for furniture and fixtures  and the change in advances from joint interest owners.

 

The financing activity during the first nine months of 2012 included $2.0 million in borrowings and $10,544,969 of repayments under our prior revolving credit facility.

 

Results of Operations

 

The Third Quarter of 2013 Compared to the Third Quarter of 2012

 

Oil and Gas Revenue and Production

 

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

 

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Table of Contents

 

 

 

Three Months Ended
September 30,

 

Year over Year Change

 

 

 

2013

 

2012

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

448,095

 

516,268

 

(68,173

)

(13

)%

Average sales price per Mcf

 

$

4.40

 

$

2.81

 

$

1.59

 

57

%

Natural gas revenue

 

$

1,973,446

 

$

1,450,782

 

$

522,664

 

36

%

 

 

 

 

 

 

 

 

 

 

Oil production (Bbl)

 

5,882

 

4,304

 

1,578

 

37

%

Average sales price per Bbl

 

$

89.57

 

$

83.14

 

$

6.43

 

8

%

Oil revenue

 

$

526,879

 

$

357,843

 

$

169,036

 

47

%

 

 

 

 

 

 

 

 

 

 

Total oil and gas revenue

 

$

2,500,325

 

$

1,808,625

 

$

691,700

 

38

%

 

 

 

 

 

 

 

 

 

 

Equivalent production (Mcfe)

 

483,387

 

542,092

 

(58,705

)

(11

)%

 

The increase in oil and gas revenue of $691,700 during the third quarter of 2013 compared with the third quarter of 2012 was comprised of a 57% increase in gas prices from $2.81 in 2012 to $4.40 in 2013 and an 8% increase in oil prices from $83.14 in 2012 to $89.57 in 2013 partially offset by an 11% decrease in equivalent oil and gas production. The decrease in equivalent oil and gas production was primarily due to normal production declines. The $691,700 increase in oil and gas revenue during the third quarter of 2013 represents an increase of $851,316 related to the increase in oil and gas prices and a decrease of $159,616 related to the equivalent production decrease.

 

Lease Operating Expenses

 

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

 

 

 

For the Three Months
Ended September 30,

 

Year over Year Change

 

 

 

2013

 

2012

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Direct operating expenses and overhead

 

$

737,886

 

$

696,834

 

$

41,052

 

6

%

Workover expense

 

1,230

 

226,634

 

(225,404

)

(99

)%

Total operating expenses

 

$

739,116

 

$

923,468

 

$

(184,352

)

(20

)%

Operating expenses per Mcfe

 

$

1.53

 

$

1.70

 

$

(0.17

)

(10

)%

 

 

 

 

 

 

 

 

 

 

Production and property taxes

 

$

76,179

 

$

52,052

 

$

24,127

 

46

%

Production and property taxes per Mcfe

 

$

0.16

 

$

0.10

 

$

0.06

 

60

%

 

 

 

 

 

 

 

 

 

 

Total lease operating expense

 

$

815,295

 

$

975,520

 

$

(160,225

)

(16

)%

 

 

 

 

 

 

 

 

 

 

Total lease operating expense per Mcfe

 

$

1.69

 

$

1.80

 

$

(0.11

)

(6

)%

 

Lease operating expense decreased $160,225 during the third quarter of 2013 compared with the third quarter of 2012. The decrease is primarily due to a decrease in workover expenses because of fewer projects during the third quarter of 2013.

 

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Table of Contents

 

Transportation and Processing

 

Transportation and processing costs of $820,411 ($1.70 per Mcfe) and $326,861 ($0.60 per Mcfe) during the three months ended September 30, 2013 and 2012, respectively, represent the costs we incurred to transport and process the gas production from our wells. The increase in these expenses during the third quarter of 2013 reflects higher transportation and processing costs related to the cryogenic processing which began in early February 2013. Additionally, $156,000 ($0.32 per Mcfe) of shortfall commitment fees were accrued during the third quarter of 2013.

 

Depletion, Depreciation, Amortization and Accretion

 

Depletion, depreciation, amortization and accretion expense during the third quarters of 2013 and 2012 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to our asset retirement obligation. This expense decreased $168,515 during the third quarter of 2013 compared to the third quarter of 2012 primarily due to the decrease in the full cost pool resulting from property impairments during 2012, as discussed below.

 

Impairment

 

Impairment expense during the third quarter of 2013 represents the decrease in the market value of our inventory.

 

As of September 30, 2012, our full cost pool exceeded the ceiling limitation based on the average, first-day-of-the-month oil and gas prices of $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012. Therefore, impairment expense of $1,016,000 was recorded during the quarter ended September 30, 2012.

 

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 September 30,

 

Year over Year
Change

 

 

 

2013

 

2012

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Total general and administrative costs

 

$

1,218,021

 

$

1,411,094

 

$

193,073

 

14

%

General and administrative costs allocated to operating activities

 

(352,719

)

(336,117

)

(16,602

)

(5

)%

General and administrative expense

 

$

865,302

 

$

1,074,977

 

$

(209,675

)

20

%

General and administrative expenses per Mcfe

 

$

1.79

 

$

1.98

 

$

0.19

 

10

%

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 

$

39,399

 

$

79,086

 

$

(39,687

)

(50

)%

Stock-based compensation per Mcfe

 

$

0.08

 

$

0.15

 

$

(0.07

)

(47

)%

 

 

 

 

 

 

 

 

 

 

Total general and administrative expense including stock-based compensation

 

$

904,701

 

$

1,154,063

 

$

(249,362

)

(22

)%

 

 

 

 

 

 

 

 

 

 

Total general and administrative expense per Mcfe

 

$

1.87

 

$

2.13

 

$

0.26

 

12

%

 

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Table of Contents

 

General and administrative expense including stock-based compensation expense decreased by $249,362 during the third quarter of 2013 as compared with the third quarter of 2012 primarily due to our implementation of cost saving measures.

 

Interest Expense

 

Interest expense increased $325,115 during the third quarter of 2013 as compared with the third quarter of 2012, primarily due to the increase in discount amortization and the default interest associated with our 2015 Notes.

 

Derivative Gains

 

Derivative gains during the quarters ended September 30, 2013 and 2012 represents the unrealized gains on our warrant derivative liability.

 

Amortization of Deferred Income from Sale of Assets

 

The amortization of the deferred income from the sale of assets during the quarters ended September 30, 2013 and 2012 represents the amortization of the excess of proceeds received over the carrying value of our gathering system and evaporative facilities sold during March 2010.

 

The First Nine Months of 2013 Compared to the First Nine Months of 2012

 

Oil and Gas Revenue and Production

 

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

 

 

 

Nine Months Ended
September 30,

 

Year over Year Change

 

 

 

2013

 

2012

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcf)

 

1,402,018

 

1,910,977

 

(508,959

)

(27

)%

Average sales price per Mcf

 

$

4.13

 

$

2.63

 

$

1.50

 

57

%

Natural gas revenue

 

$

5,793,536

 

$

5,031,824

 

$

761,712

 

15

%

 

 

 

 

 

 

 

 

 

 

Oil production (Bbl)

 

17,131

 

18,398

 

(1,267

)

(7

)%

Average sales price per Bbl

 

$

84.02

 

$

84.84

 

$

(0.82

)

(1

)%

Oil revenue

 

$

1,439,290

 

$

1,560,941

 

$

(121,651

)

(8

)%

 

 

 

 

 

 

 

 

 

 

Total oil and gas revenue

 

$

7,232,826

 

$

6,592,765

 

$

640,061

 

10

%

 

 

 

 

 

 

 

 

 

 

Equivalent production (Mcfe)

 

1,504,804

 

2,021,365

 

(516,561

)

(26

)%

 

The increase in oil and gas revenue of $640,061 during the first nine months of 2013 compared with the first nine months of 2012 was comprised of a 57% increase in average gas prices partially offset by a 26% decrease in equivalent oil and gas production and a 1% decrease in oil prices from $84.84 in 2012 to $84.02 in 2013. The decrease in equivalent oil and gas production was primarily due to the Uinta Basin Transaction and normal production declines. The $640,061 increase in oil and gas revenue during the first nine months of 2013 represents an increase of $2,856,143 related to the increase in gas prices partially

 

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Table of Contents

 

offset by a decrease of $2,200,982 related to the equivalent production decrease and a decrease of $15,100 related to the decrease in oil prices.

 

Lease Operating Expenses

 

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

 

 

 

For the Nine Months Ended
September 30,

 

Year over Year Change

 

 

 

2013

 

2012

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Direct operating expenses and overhead

 

$

2,117,361

 

$

2,465,125

 

$

(347,764

)

(14

)%

Workover expense

 

145,296

 

1,168,222

 

(1,022,926

)

(88

)%

Total operating expenses

 

$

2,262,657

 

$

3,633,347

 

$

(1,370,690

)

(38

)%

Operating expenses per Mcfe

 

$

1.50

 

$

1.80

 

$

(0.30

)

(17

)%

 

 

 

 

 

 

 

 

 

 

Production and property taxes

 

$

153,902

 

$

182,640

 

$

(28,738

)

(16

)%

Production and property taxes per Mcfe

 

$

0.10

 

$

0.09

 

$

0.01

 

11

%

 

 

 

 

 

 

 

 

 

 

Total lease operating expense

 

$

2,416,559

 

$

3,815,987

 

$

(1,399,428

)

(37

)%

 

 

 

 

 

 

 

 

 

 

Total lease operating expense per Mcfe

 

$

1.60

 

$

1.89

 

$

(0.29

)

(15

)%

 

Lease operating expense decreased $1,399,428 during the first nine months of 2013 compared with the first nine months of 2012. The decrease is primarily due to the conveyance of a 50% interest in certain of our properties in the Uinta Basin Transaction which closed during March 2012 and a decrease in workover expenses because of fewer projects during the first nine months of 2013.

 

Transportation and Processing

 

Transportation and processing costs were $2,179,655 ($1.45 per Mcfe) and $1,502,224 ($0.74 per Mcfe) during the nine months ended September 30, 2013 and 2012, respectively. Additionally, $373,000 ($0.25 per Mcfe) of shortfall commitment fees were accrued during the first nine months of 2013. The increase in these expenses during the first nine months of 2013 reflects higher transportation and processing costs related to the cryogenic processing which began in early February 2013.

 

Depletion, Depreciation, Amortization and Accretion

 

Depletion, depreciation, amortization and accretion expense decreased $898,003 during the first nine months of 2013 compared to the first nine months of 2012 primarily due to the decrease in the full cost pool resulting from property impairments during 2012, as discussed below, and the production decline related to the Uinta Basin Transaction during March 2012.

 

Impairment

 

Impairment expense during the first nine months of 2013 represents the decrease in the market value of our inventory.

 

As of September 30, 2012, June 30, 2012 and March 31, 2012, our full cost pool exceeded the ceiling

 

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limitation based on the average, first-day-of-the-month oil and gas prices of $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012 and $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012. Total impairment expense of $9,071,000 was recorded during the nine months ended September 30, 2012.

 

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 Nine Months
Ended September 30,

 

Year over Year Change

 

 

 

2013

 

2012

 

Amount

 

Percentage

 

 

 

 

 

 

 

 

 

 

 

Total general and administrative costs

 

$

4,317,089

 

$

4,493,167

 

$

(176,078

)

(4

)%

General and administrative costs allocated to operating activities

 

(1,092,652

)

(1,037,450

)

55,202

 

5

%

General and administrative expense

 

$

3,224,437

 

$

3,455,717

 

$

(231,280

)

(7

)%

General and administrative expenses per Mcfe

 

$

2.14

 

$

1.71

 

$

0.43

 

25

%

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 

$

139,655

 

$

215,947

 

$

(76,292

)

(35

)%

Stock-based compensation per Mcfe

 

$

0.09

 

$

0.11

 

$

(0.02

)

(18

)%

 

 

 

 

 

 

 

 

 

 

Total general and administrative expense including stock-based compensation

 

$

3,364,092