10-Q 1 a14-9719_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 


 

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

 

For the quarterly period ended March 31, 2014

 

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 001-32960

 


 

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

 


 

Delaware

 

76-0662382

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification Number)

 

909 Fannin, Suite 1850

Houston, Texas 77010

(713) 659-3855

(Address of principal executive offices and telephone number, including area code)

 

N/A

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

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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.  x  Yes  o  No

 

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).  x  Yes  o  No

 

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

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company x

 

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

 

As of May 1, 2014, 40,649,440 shares and 6,188,032 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Part I. Financial Information

 

 

 

 

 

 

 

 

Item 1.

Consolidated Financial Statements (Unaudited)

 

 

 

 

 

Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013

 

3

 

 

 

Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013

 

4

 

 

 

Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2014 and 2013

 

5

 

 

 

Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013

 

6

 

 

 

Notes to Consolidated Financial Statements (Unaudited)

 

7

 

 

 

 

 

 

 

 

Item 2.

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

 

17

 

 

 

 

 

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

 

25

 

 

 

 

 

 

 

 

Item 4.

Controls and Procedures

 

25

 

 

 

 

 

Part II. Other Information

 

 

 

 

 

 

 

 

Item 1.

Legal Proceedings

 

25

 

 

 

 

 

 

 

 

Item 1A.

Risk Factors

 

25

 

 

 

 

 

 

 

 

Item 6.

Exhibits

 

27

 

 

2



Table of Contents

 

Part I. FINANCIAL INFORMATION

 

Item 1.                                   Financial Statements

 

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

 

 

March 31,
2014

 

December 31,
2013

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

7,559,114

 

$

8,108,272

 

Assets held for sale

 

46,451,620

 

 

Accounts receivable, net of allowance of $14,744 at March 31, 2014 and December 31, 2013

 

10,018

 

2,900,807

 

Other current assets

 

101,909

 

692,740

 

Total current assets

 

54,122,661

 

11,701,819

 

Natural gas properties—utilizing the full cost method of accounting:

 

 

 

 

 

Proved natural gas properties

 

 

333,109,974

 

Other property and equipment

 

 

3,158,701

 

Total property and equipment

 

 

336,268,675

 

Less accumulated depreciation, depletion, amortization and impairment of gas properties

 

 

(293,939,624

)

Property and equipment—net

 

 

42,329,051

 

Other noncurrent assets:

 

 

 

 

 

Other

 

47,409

 

769,384

 

Total other noncurrent assets

 

47,409

 

769,384

 

TOTAL ASSETS

 

$

54,170,070

 

$

54,800,254

 

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable

 

$

531,263

 

$

3,541,770

 

Royalties payable

 

 

3,656,272

 

Accrued liabilities

 

8,910

 

1,073,653

 

Liabilities held for sale

 

87,242,070

 

 

Derivative liability—natural gas contracts

 

 

834,151

 

Asset retirement obligations

 

 

265,470

 

Current portion of long-term debt

 

 

71,550,000

 

Total current liabilities

 

87,782,243

 

80,921,316

 

Asset retirement obligations

 

1,359,671

 

8,915,407

 

Derivative liability—natural gas contracts

 

 

709,571

 

Other long-term accrued liabilities

 

 

113,434

 

TOTAL LIABILITIES

 

89,141,914

 

90,659,728

 

Commitments and contingencies (Note 14)

 

 

 

 

 

Mezzanine equity:

 

 

 

 

 

Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,435; redemption amount $61,880,320; $.001 par value; 7,401,832 shares authorized, 6,188,032 and 6,000,571 shares were issued and outstanding at March 31, 2014 and December 31, 2013, respectively

 

44,649,612

 

43,404,993

 

Stockholders’ Deficit:

 

 

 

 

 

Preferred stock, $0.001 par value—2,598,168 shares authorized, none issued

 

 

 

Common stock, $0.001 par value—authorized 125,000,000 shares; 40,659,872 issued and 40,649,440 outstanding at March 31, 2014 and 40,662,749 issued and 40,652,317 outstanding at December 31, 2013

 

40,663

 

40,663

 

Treasury stock, at cost—10,432 shares at March 31, 2014 and December 31, 2013

 

(94,424

)

(94,424

)

Paid-in capital

 

186,321,871

 

187,527,716

 

Retained deficit

 

(265,889,566

)

(266,738,422

)

Total stockholders’ deficit

 

(79,621,456

)

(79,264,467

)

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT

 

$

54,170,070

 

$

54,800,254

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited).

 

3



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

 

 

 

2014

 

2013

 

Expenses:

 

 

 

 

 

Depreciation, depletion and amortization

 

$

113,817

 

$

34,372

 

General and administrative

 

1,029,604

 

998,233

 

Restructuring costs

 

 

70,188

 

Total operating expenses

 

1,143,421

 

1,102,793

 

 

 

 

 

 

 

Operating loss

 

(1,143,421

)

(1,102,793

)

 

 

 

 

 

 

Other expense

 

(18,534

)

(28,648

)

 

 

 

 

 

 

Loss before income taxes from continuing operations

 

(1,161,955

)

(1,131,441

)

 

 

 

 

 

 

Income tax expense

 

6,250

 

6,250

 

 

 

 

 

 

 

Loss from continuing operations

 

(1,168,205

)

(1,137,691

)

 

 

 

 

 

 

Discontinued operations

 

2,017,061

 

(4,617,223

)

 

 

 

 

 

 

Net income (loss)

 

$

848,856

 

$

(5,754,914

)

 

 

 

 

 

 

Accretion of discount on Series A Convertible Redeemable Preferred Stock

 

(644,744

)

(493,537

)

Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock

 

(599,875

)

(1,075,685

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(568

)

(633

)

 

 

 

 

 

 

Net loss available to common stockholders

 

$

(396,331

)

$

(7,324,769

)

 

 

 

 

 

 

Net loss per common share—basic:

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.06

)

$

(0.07

)

Income (loss) per common share from discontinued operations

 

0.05

 

(0.11

)

Net loss per common share—basic

 

$

(0.01

)

$

(0.18

)

 

 

 

 

 

 

Net loss per common share—diluted:

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.06

)

$

(0.07

)

Income (loss) per common share from discontinued operations

 

0.05

 

(0.11

)

Net loss per common share—diluted

 

$

(0.01

)

$

(0.18

)

 

 

 

 

 

 

Weighted average number of common shares:

 

 

 

 

 

Basic

 

40,514,097

 

40,456,773

 

Diluted

 

40,514,097

 

40,456,773

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited).

 

4



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Net income (loss)

 

$

848,856

 

$

(5,754,914

)

 

 

 

 

 

 

Other comprehensive income (loss), net of related taxes:

 

 

 

 

 

Foreign currency translation adjustment

 

 

1,232

 

Unrealized gain on available for sale securities

 

 

20,063

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

848,856

 

$

(5,733,619

)

 

See accompanying Notes to Consolidated Financial Statements (Unaudited).

 

5



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

 

 

 

2014

 

2013

 

Cash flows provided by operating activities:

 

 

 

 

 

Loss from continuing operations

 

$

(1,168,205

)

$

(1,137,691

)

Adjustments to reconcile loss from continuing operations to net cash flows (used in) provided by continuing operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

113,817

 

34,372

 

Stock-based compensation

 

39,343

 

58,724

 

Changes in operating assets and liabilities:

 

 

 

 

 

Other current assets

 

237,002

 

160,784

 

Accounts payable

 

23,878

 

(12,317

)

Other accrued liabilities

 

(5,886

)

7,905

 

Net cash used in continuing operating activities

 

(760,051

)

(888,223

)

 

 

 

 

 

 

Income (loss) from discontinued operations

 

2,017,061

 

(4,617,223

)

Adjustments to reconcile Income (loss) from discontinued operations to net cash flows provided by discontinued operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

715,892

 

1,471,994

 

Amortization of debt issuance costs

 

218,357

 

225,870

 

Unrealized losses from the change in market value of open derivative contracts

 

271,839

 

8,634,871

 

Loss on sale of other assets

 

16,687

 

27,616

 

Accretion expense

 

194,884

 

317,013

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(619,091

)

1,734,662

 

Other current assets

 

(698,632

)

2,476

 

Accounts payable

 

(744,681

)

(2,670,338

)

Other accrued liabilities

 

297,431

 

576,918

 

Net cash provided by discontinued operating activities

 

1,669,747

 

5,703,859

 

 

 

 

 

 

 

Net cash provided by operating activities

 

909,696

 

4,815,636

 

 

 

 

 

 

 

Cash flows provided by (used in) investing activities:

 

 

 

 

 

Continuing operations:

 

 

 

 

 

Proceeds from the sale of other assets

 

140,000

 

 

Net cash provided by investing activities- continuing operations

 

140,000

 

 

Discontinued operations:

 

 

 

 

 

Capital expenditures

 

(68,286

)

(172,466

)

Proceeds from sale of other assets

 

20,000

 

9,375

 

Net cash used in investing activities- discontinued operations

 

(48,286

)

(163,091

)

 

 

 

 

 

 

Net cash provided by (used in) investing activities

 

91,714

 

(163,091

)

 

 

 

 

 

 

Cash flows used in financing activities:

 

 

 

 

 

Continuing operations:

 

 

 

 

 

Dividends paid

 

(568

)

(633

)

Treasury stock

 

 

(17

)

Net cash used in financing activities- continuing operations

 

(568

)

(650

)

Discontinued operations:

 

 

 

 

 

Repayment of borrowings under Credit Agreement

 

(1,550,000

)

(4,500,000

)

Deferred financing costs

 

 

(3,801

)

Net cash used in financing activities- discontinued operations

 

(1,550,000

)

(4,503,801

)

 

 

 

 

 

 

Net cash used in financing activities

 

(1,550,568

)

(4,504,451

)

 

 

 

 

 

 

(Decrease) increase in cash and cash equivalents

 

(549,158

)

148,094

 

Cash and cash equivalents at beginning of period

 

8,108,272

 

7,234,225

 

Cash and cash equivalents at end of period

 

$

7,559,114

 

$

7,382,319

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid during the period for:

 

 

 

 

 

Interest expense

 

$

705,116

 

$

1,664,956

 

Income taxes

 

$

6,250

 

$

6,250

 

 

 

 

 

 

 

Significant noncash investing and financing activities:

 

 

 

 

 

Accrued capital expenditures

 

$

21,266

 

$

357,856

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

6



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

Note 1—Organization and Our Business

 

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. We are primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production is CBM, which is a dry natural gas containing no hydrocarbon liquids. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the central Appalachian Basin in Virginia and West Virginia.

 

The accompanying unaudited consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and results of operations for, the interim periods presented. These unaudited consolidated financial statements have been prepared in accordance with the guidelines of interim reporting; therefore, they do not include all disclosures required for our year-end audited consolidated financial statements prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim period results are not necessarily indicative of results of operations or cash flows for the full year. These unaudited consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements for the fiscal year ended December 31, 2013 and the accompanying notes included in our Annual Report on Form 10-K, which we filed with the Securities and Exchange Commission (the “SEC”) on March 31, 2014.

 

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Note 2—Recent Accounting Pronouncement

 

In April 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when an entity meets the criteria to be classified as held for sale, the component of an entity or group of components of an entity is disposed of by sale, or the component of an entity or group of components of an entity is disposed of other than by sale. ASU 2014-08 should be applied when any of these occur within annual periods beginning on or after December 15, 2014. Early adoption is permitted, however, the Company elected not to early adopt the ASU. The ASU requires entities to separately present assets and liabilities of a discontinued operation for all periods presented in the balance sheet.  The impact of adoption of the ASU would be the reclassification of all of the assets included in the Asset Sale as Assets held for sale and all related liabilities as Liabilities held for sale, both in the Consolidated Balance Sheet (Unaudited) as of December 31, 2013.

 

Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement

 

On May 12, 2014, we closed the previously announced sale of substantially all of our remaining assets which consisted of coalbed methane interests and other assets located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership.  The purchase price of $107.0 million was adjusted downward $9.5 million primarily to account for cash flows from the effective date to closing, resulting in net proceeds of $97.5 million.  The final adjusted purchase price is to be determined within 95 days of the close of the Asset Sale or by August 15, 2014.

 

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the financial institutions party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”).  Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled $69.1 million. As a result, we satisfied all of our material obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.

 

Note 4—Assets and Liabilities Held For Sale and Discontinued Operations

 

As a result of meeting all of the relevant criteria established under GAAP, we have classified all of the assets included in the Asset Sale as Assets held for sale and all related liabilities as Liabilities held for sale, both in the Consolidated Balance Sheet (Unaudited) as of March 31, 2014. Additionally, the related operating activities are presented as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013.

 

Assets held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014 include:

 

Accounts receivable

 

$

3,509,880

 

 

 

 

 

Other current assets

 

723,456

 

 

 

 

 

Proved gas properties

 

333,172,981

 

Other property and equipment

 

3,083,974

 

Total property and equipment

 

336,256,955

 

Less accumulated depreciation, depletion, amortization and impairments

 

(294,727,614

)

Property and equipment—net

 

41,529,341

 

 

 

 

 

Other noncurrent assets

 

688,943

 

 

 

 

 

Assets held for sale

 

$

46,451,620

 

 

Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014 include:

 

Accounts payable

 

$

2,123,798

 

Royalties payable

 

3,816,900

 

Accrued liabilities

 

1,506,738

 

Asset retirement obligations

 

7,979,073

 

Current portion of long-term debt

 

70,000,000

 

Derivative liability—natural gas contracts—current

 

1,441,458

 

Derivative liability—natural gas contracts—non-current

 

374,103

 

Liabilities held for sale

 

$

87,242,070

 

 

Results for activities reported as discontinued operations for the three months ended March 31, 2014 and 2013 were as follows:

 

 

 

2014

 

2013

 

Revenues:

 

 

 

 

 

Gas sales

 

$

9,678,375

 

$

10,879,264

 

Other

 

17,775

 

44,956

 

Total revenues

 

9,696,150

 

10,924,220

 

Expenses:

 

 

 

 

 

Lease operating expense

 

2,551,646

 

4,469,239

 

Compression and transportation expense

 

1,673,399

 

1,838,636

 

Production taxes

 

578,487

 

550,546

 

Depreciation, depletion and amortization

 

715,892

 

1,471,994

 

Losses on natural gas derivatives

 

1,237,716

 

5,535,119

 

Total operating expenses

 

6,757,140

 

13,865,534

 

Operating income (loss)

 

2,939,010

 

(2,941,314

)

Interest expense

 

(923,511

)

(1,676,329

)

Interest income

 

1,562

 

420

 

Income from discontinued operations

 

$

2,017,061

 

$

(4,617,223

)

 

8



Table of Contents

 

Note 5—Net Loss Per Common Share

 

Net loss per common share—basic is calculated by dividing Net loss available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net loss per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net loss available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net loss per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential shares of common stock would have an anti-dilutive effect. A reconciliation of Net loss per common share for the three months ended March 31, 2014 and 2013 is as follows:

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Net loss available to common stockholders

 

$

(396,331

)

$

(7,324,769

)

Income (loss) from discontinued operations

 

$

2,017,061

 

$

(4,617,223

)

Net loss per common share—basic:

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.06

)

$

(0.07

)

Income (loss) per common share from discontinued operations

 

0.05

 

(0.11

)

Net loss per common share—basic

 

$

(0.01

)

$

(0.18

)

Net loss per common share—diluted:

 

 

 

 

 

Net loss per common share from continuing operations

 

$

(0.06

)

$

(0.07

)

Income (loss) per common share from discontinued operations

 

0.05

 

(0.11

)

Net loss per common share—diluted

 

$

(0.01

)

$

(0.18

)

Weighted average number of common shares:

 

 

 

 

 

Basic

 

40,514,097

 

40,456,773

 

Diluted

 

40,514,097

 

40,456,773

 

 

Net loss per common share—diluted for the three months ended March 31, 2014 excluded the effect of outstanding exercisable options to purchase 1,555,508 shares, 135,343 weighted average restricted shares outstanding, and 6,188,032 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”) (47,600,246 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a Net loss available to common stockholders which caused the options and restricted shares to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net loss available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net loss available to common stockholders for the three months ended March 31, 2014 for accretion of and dividends paid for Preferred Stock of $644,744 and $600,443, respectively, in computing Net loss per common share—diluted as the preferred shares were anti-dilutive.

 

Net loss per common share—diluted for the three months ended March 31, 2013 excluded the effect of outstanding exercisable options to purchase 2,365,466 shares, 233,099 weighted average restricted shares outstanding, and 5,305,865 shares of Preferred Stock (40,814,346 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a Net loss available to common stockholders which caused the options and restricted shares to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net loss available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net loss available to common stockholders for the three months ended March 31, 2013 for accretion of and dividends paid for Preferred Stock of $493,537 and $1,076,318, respectively, in computing Net loss per common share—diluted as the preferred shares were anti-dilutive.

 

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Note 6—Gas Properties

 

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale which included substantially all of our gas properties. Proved gas properties and accumulated depreciation, depletion, amortization and impairment of gas properties have been classified as a current asset in Assets held for sale in the Consolidated Balance Sheet (Unaudited) as of March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

 

The method of accounting for oil and gas producing activities determines which costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for our gas properties. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized.

 

Gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved gas reserves.

 

Estimation of proved gas reserves involves professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during future reporting periods. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.

 

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of estimated future net revenues, discounted at 10% per annum, plus cost of properties not being amortized plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.

 

The ceiling test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. In addition, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

 

For the twelve months ended March 31, 2014, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $4.02 per Mcf, resulting in a natural gas price of $4.14 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, no write-down of the carrying value of our U.S. full cost pool was required at March 31, 2014.

 

For the twelve months ended March 31, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $2.97 per Mcf, resulting in a natural gas price of $3.03 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, no write-down of the carrying value of our U.S. full cost pool was required at March 31, 2013.

 

Note 7—Asset Retirement Obligations

 

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. The buyer has assumed the entire current portion of our asset retirement obligation (“ARO”). Certain asset retirement obligations have been classified as a current liability in Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

 

We record an ARO in the Consolidated Balance Sheets (Unaudited) and capitalize the asset retirement costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date the abandonment obligation was incurred using an assumed cost of funds for GeoMet. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed cost of funds. Periodically, we update the cost assumptions resulting from market changes and revise the liability recorded accordingly.

 

The following table details the changes to our ARO for the three months ended March 31, 2014:

 

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Current portion of asset retirement obligation at January 1, 2014

 

$

265,470

 

Add: Long-term portion of asset retirement obligation at January 1, 2014

 

8,915,407

 

 

 

 

 

Asset retirement obligation at January 1, 2014

 

9,180,877

 

Settlements

 

(37,017

)

Accretion

 

194,884

 

 

 

 

 

Asset retirement obligation at March 31, 2014

 

9,338,744

 

Less: Current portion of asset retirement obligation (1)

 

(7,979,073

)

 

 

 

 

Long-term portion of asset retirement obligation at March 31, 2014

 

$

1,359,671

 

 


(1)         The current portion of ARO as of March 31, 2014 has been classified as Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

 

Note 8—Derivative Instruments and Hedging Activities

 

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. On that date, in connection with the closing of the Asset Sale, we settled all of our outstanding natural gas hedge positions for approximately $3.1 million.

 

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. At March 31, 2014, we do not have the ability to enter into natural gas hedges because we do not have the credit capacity with our existing natural gas hedge counterparties.

 

In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has historically hedged natural gas prices primarily using derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. We entered into hedging transactions, generally for forward periods up to two years or more, which increased the probability of achieving our targeted level of cash flows.  Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

 

Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

 

Commodity Price Risk and Related Hedging Activities

 

At March 31, 2014, we had the following natural gas derivative contracts:

 

Contract
Type

 

Period

 

Volume
(MMBtu)

 

Sold Ceiling/
Bought Floor

 

Derivative
liability—
current (1)

 

Derivative
liability—
non-current (1)

 

Total Fair
Value of
Contract

 

Collar

 

April 2014 through December 2015

 

3,200,000

 

$

4.30/$3.60

 

$

(671,882

)

$

(144,771

)

$

(816,653

)

Collar

 

April 2014 through December 2015

 

3,200,000

 

$

4.20/$3.50

 

(769,576

)

(229,332

)

(998,908

)

 

 

 

 

6,400,000

 

 

 

$

(1,441,458

)

$

(374,103

)

$

(1,815,561

)

 


(1)                  At March 31, 2014, Derivative liability—current and Derivative liability—non-current have each been classified as a current liability in Liabilities held for sale in the Consolidated Balance Sheet (Unaudited). See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

 

At December 31, 2013, we had the following natural gas derivative contracts:

 

Contract
Type

 

Period

 

Volume
(MMBtu)

 

Fixed Price or
Sold Ceiling/

Bought Floor

 

Derivative
liability—
current

 

Derivative
liability—
non-current

 

Total Fair
Value of
Contract

 

Swap

 

January 2014 through March 2014

 

360,000

 

$

3.82

 

$

(164,121

)

$

 

$

(164,121

)

Collar

 

January 2014 through December 2015

 

3,650,000

 

$

4.30/$3.60

 

(280,392

)

(296,436

)

(576,828

)

Collar

 

January 2014 through December 2015

 

3,650,000

 

$

4.20/$3.50

 

(389,638

)

(413,135

)

(802,773

)

 

 

 

 

7,660,000

 

 

 

$

(834,151

)

$

(709,571

)

$

(1,543,722

)

 

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants or affiliates of the participants in our credit agreement and the collateral for the outstanding borrowings

 

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under our credit agreement is used as collateral for our hedges. We do not have rights to collateral from our counterparties, nor do we have rights of offset against borrowings under our credit agreement.

 

We estimate the fair value of our natural gas derivative contracts using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. In order to estimate the fair value of our natural gas derivative contracts, a forward price curve and volatility estimates were compiled from sources that include NYMEX settlements and observed trading activity in the Over-the-Counter markets. Pricing estimates for the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-section of industry participants. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows. The estimated fair value of our natural gas derivative contracts also reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our counterparties’ and our credit risk, we have considered the effect of credit risk on the fair value of our natural gas derivative contracts. The consideration for discounting our counterparties’ liabilities (our assets) was based on the difference between the S&P credit rating of a comparable company to our counterparties and the 1-Year Treasury bill rate, both at the reporting date. The consideration for discounting our liabilities was based on the difference between the market weighted average cost of debt capital plus a premium over the capital asset pricing model and the 1-Year Treasury bill rate.

 

We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended March 31, 2014. Based on the use of observable market inputs, we have designated these types of instruments designated below as Level 2. The fair value of our Level 2 derivative instruments were as follows:

 

 

 

Asset Derivatives

 

Liability Derivatives

 

 

 

March 31, 2014

 

December 31, 2013

 

March 31, 2014

 

December 31, 2013

 

 

 

Balance Sheet
Location

 

Fair
Value

 

Balance Sheet
Location

 

Fair
Value

 

Balance Sheet
Location

 

Fair
Value

 

Balance Sheet
Location

 

Fair
Value

 

Derivatives not designated as hedging instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas hedge positions

 

Derivative asset
(current)

 

$

 

Derivative asset
(current)

 

$

 

Derivative liability
(current)

 

$

1,441,458

 

Derivative liability
(current)

 

$

834,151

 

Natural gas hedge positions

 

Derivative asset
(non- current)

 

 

Derivative asset
(non- current)

 

 

Derivative liability
(non- current)

 

374,103

 

Derivative liability
(non-current)

 

709,571

 

Total derivatives not designated as hedging instruments

 

 

 

$

 

 

 

$

 

 

 

$

1,815,561

 

 

 

$

1,543,722

 

 

The following losses on our hedging instruments have been classified as Discontinued operations on the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

 

 

 

Location of (Gain) or Loss Recognized in

 

Amount of (Gain) or Loss
Recognized in Income on
Derivatives

 

Derivatives not designated as hedging instruments

 

Income on Derivatives

 

2014

 

2013

 

Natural gas collar/swap settled positions

 

Discontinued operations

 

$

965,877

 

$

(3,099,752

)

Natural gas collar/swap unsettled positions

 

Discontinued operations

 

271,839

 

8,634,871

 

 

 

 

 

 

 

 

 

Total loss

 

 

 

$

1,237,716

 

$

5,535,119

 

 

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Table of Contents

 

Note 9—Long-Term Debt

 

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. Immediately following the closing of the Asset Sale, we repaid all outstanding borrowing under our credit agreement of $69.1 million. Borrowings under our credit agreement have been classified as Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

 

During 2012, the amounts borrowed under our credit agreement exceeded the borrowing base.  Borrowings under our credit agreement at August 8, 2012 totaled $148.6 million. On August 8, 2012, in connection with the excess of borrowings over the borrowing base, we amended our credit agreement to provide for a tranche A loan in the amount of our borrowing base and a tranche B loan in the amount of the borrowing base deficiency.

 

On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in the state of Alabama. Simultaneously with the close of the property sale, approximately $57.0 million was used to repay outstanding borrowings under the Company’s credit agreement, which eliminated the borrowing base deficiency. After this repayment, borrowings outstanding under our credit agreement totaled $77.0 million.

 

Our credit agreement no longer provides for loans to be available on a revolving basis up to the amount of the borrowing base. As a result, the current outstanding loans, once repaid, may not be re-borrowed. All outstanding borrowings under our credit agreement are due and payable on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement. Our borrowing base is defined to be equal to the amount borrowed under our credit agreement. Our credit agreement provides for interest to accrue at a rate calculated, at our option, at the Adjusted Base Rate plus a margin of 2.00% or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. All financial covenants were deleted by the amendment to our credit agreement and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.0 million in 2013 and thereafter).

 

As of March 31, 2014 and December 31, 2013, we had $70.0 million and $71.6 million, respectively, of borrowings outstanding under our credit agreement. As of March 31, 2014 and December 31, 2013, the interest rates applied to borrowings were 3.21% and 3.24%, respectively. For the three months ended March 31, 2014, we had no borrowings and made payments of $1.6 million under our credit agreement. For the three months ended March 31, 2014 interest on the borrowings averaged 4.02%. For the three months ended March 31, 2013, we had no borrowings and made payments of $4.5 million under our credit agreement. For the three months ended March 31, 2013 interest on the borrowings averaged 4.27%.

 

The following is a summary of our long-term debt at March 31, 2014 and December 31, 2013:

 

 

 

March 31,
2014

 

December 31,
2013

 

 

 

 

 

 

 

Borrowings under credit agreement

 

$

70,000,000

 

$

71,550,000

 

Less current maturities included in current liabilities

 

(70,000,000

)

(71,550,000

)

 

 

 

 

 

 

Total long-term debt

 

$

 

$

 

 

We record our debt instruments based on contractual terms. We did not elect to apply the fair value option for recording financial assets and financial liabilities. We measure the fair value of our debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 or 2 within the fair value hierarchy. Fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our credit risk, we have considered the effect of our credit risk on the fair value of the long-term debt. This consideration involved discounting our long-term debt based on the difference between the market weighted average cost of equity capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt.  The fair value of long-term debt as of March 31, 2014 and December 31, 2013 was estimated to be approximately $69.4 million and $70.1 million, respectively.

 

Note 10—Income Taxes

 

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. In connection with the closing of the Asset Sale, we estimated income tax payable in the amount of $1.2 million, representing alternative minimum tax. No regular income tax is expected to result from the transaction as we estimate sufficient net operating losses will be carried forward from prior years to offset the estimated gain on the Asset Sale.

 

We record our income taxes using an asset and liability approach. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities using enacted tax rates at the end of the period. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change.

 

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Table of Contents

 

For tax reporting purposes, we have federal and state net operating losses (“NOLs”) of approximately $156.1 million and $162.6 million, respectively, at March 31, 2014 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOLs of approximately $156.0 million and $162.3 million, respectively, at December 31, 2013 that were available to reduce future taxable income. Our first material federal NOL carryforward expires in 2022 and the last one expires in 2034.

 

Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012, of approximately $33.9 million at March 31, 2014 that is available to reduce future taxable capital gains and expiring in 2017. Additionally, we have a federal capital loss carryforward of $0.2 million generated by the sale of other assets in 2014.

 

At March 31, 2014, we have a valuation allowance of $83.1 million recorded against our net deferred tax asset which includes $70.2 million related to our United States operations and $13.0 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012 and other assets in 2014.

 

The income tax expense in the current year period was different than the amount computed using the statutory rate primarily due to a decrease of $0.3 million in the valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:

 

Amount computed using statutory rates

 

$

290,736

 

34.00

%

State income taxes—net of federal benefit

 

36,859

 

4.31

%

Valuation Allowance

 

(343,900

)

-40.22

%

Nondeductible items and other

 

22,555

 

2.64

%

Income tax provision

 

$

6,250

 

0.73

%

 

Note 11—Common Stock

 

As of March 31, 2014, shares of our Common Stock issued and outstanding were 40,659,872 and 40,649,440, respectively.  As of December 31, 2013, shares of our Common Stock issued and outstanding were 40,662,749 and 40,652,317, respectively. Included in shares of our Common Stock issued as of March 31, 2014 and December 31, 2013 were 10,432 shares of treasury stock held by the Company. Included in our Common Stock both issued and outstanding at March 31, 2014 and December 31, 2013 were 136,065 and 158,065 shares of restricted stock, respectively. During the three months ended March 31, 2014, 153 shares of restricted stock were forfeited and canceled upon the termination of an employee by the Company and 2,724 shares of restricted stock expired unvested and were canceled.

 

Note 12—Series A Convertible Redeemable Preferred Stock

 

At March 31, 2014 and December 31, 2013, 6,188,032 and 6,000,571 shares of Preferred Stock were issued and outstanding, respectively. At March 31, 2014, an additional 1,213,800 shares of our Preferred Stock are reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). We measure the fair value of PIK dividends using the closing quoted NASDAQ market price on the dividend date (categorized as level 1). The following table details the activity related to the Preferred Stock for the three months ended March 31, 2014:

 

 

 

Dividend Period
(Three Months Ended)

 

Date Issued

 

Number of Shares

 

Balance

 

 

 

 

 

 

 

 

 

 

 

Balance at January 1, 2014

 

 

 

 

 

6,000,571

 

$

43,404,993

 

Accretion of discount on Preferred Stock

 

 

 

 

 

 

 

644,744

 

PIK Dividends Issued for Preferred Stock :

 

3/31/14

 

3/31/14

 

187,461

 

599,875

 

Balance At March 31, 2014

 

 

 

 

 

6,188,032

 

$

44,649,612

 

 

Note 13—Share-Based Awards

 

Our 2006 Long-Term Incentive Plan (the “2006 Plan”) authorizes the granting of incentive stock options, non-qualified stock options, stock appreciation rights, stock awards, restricted stock, restricted stock units and performance awards. A maximum of 4,000,000 shares are available for grant under this plan. The 2006 Plan is available to our employees and independent directors. However, the Company does not anticipate any additional grants will be awarded under the 2006 Plan in the immediate future. The exercise price of stock options granted under this plan may not be less than the fair market value of the Common Stock on the date of grant. The options generally have a term of seven years and vest evenly over three years, except performance based awards which are granted solely to our named executive officers, and options issued to directors. Performance based awards granted under the 2006 Plan vest once the performance criteria have been met. Options granted to our directors vest immediately.

 

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Table of Contents

 

During the three months ended March 31, 2014, we recorded a compensation expense accrual of $39,343 which was allocated as an addition of $2,105 to lease operating expenses and an addition of $37,238 to general and administrative expense. During the three months ended March 31, 2013, we recorded a compensation expense accrual of $58,724 which was allocated as an addition of $6,752 to lease operating expenses and an addition of $51,972 to general and administrative expense. At March 31, 2014, the future compensation cost of all the outstanding awards is $27,150 which will be amortized over the vesting period of such stock options and restricted stock. The weighted average remaining useful life of the future compensation cost is 0.65 years.

 

Incentive Stock Options

 

The table below summarizes incentive stock option activity for the three months ended March 31, 2014:

 

 

 

Number of
Options

 

Weighted
Average
Exercise
Price

 

Average
Remaining
Contractual
Life

 

Aggregate
Intrinsic
Value

 

Outstanding at December 31, 2013

 

1,199,433

 

$

1.11

 

 

 

 

 

Forfeited

 

(18,690

)

$

1.11

 

 

 

 

 

Outstanding at March 31, 2014

 

1,180,743

 

$

1.11

 

2.5

 

$

 

Options exercisable at March 31, 2014

 

1,030,531

 

$

1.04

 

3.2

 

$

 

 

Non-Qualified Stock Options

 

The table below summarizes non-qualified stock option activity for the three months ended March 31, 2014:

 

 

 

Number of
Options

 

Weighted
Average
Exercise
Price

 

Average
Remaining
Contractual
Life

 

Aggregate
Intrinsic
Value

 

Outstanding at December 31, 2013

 

374,765

 

$

2.05

 

 

 

 

 

Outstanding at March 31, 2014

 

374,765

 

$

2.05

 

0.5

 

$

 

Options exercisable at March 31, 2014

 

333,242

 

$

2.22

 

1.3

 

$

 

 

Restricted Stock Awards

 

The table below summarizes non-vested restricted stock awards activity for the three months ended March 31, 2014:

 

 

 

Number of
Shares

 

Weighted
Average
Grant Date
Fair Value

 

Non-vested restricted stock at December 31, 2013

 

158,065

 

$

1.83

 

Vested

 

(19,123

)

$

1.32

 

Forfeited

 

(2,877

)

$

8.16

 

Non-vested restricted stock at March 31, 2014

 

136,065

 

$

1.77

 

 

Restricted Stock Unit Awards

 

On April 5, 2011, we granted 232,089 restricted stock units to our five executive officers. These restricted stock units vest upon the Company’s achievement of certain performance targets, but no earlier than ratably over the three year period following the grant date, at which time one common share will be issued and exchanged for each restricted stock unit held. If the requisite performance targets are not achieved in the seven year period ended April 5, 2018, the restricted stock units will expire. Restricted stock units are included in the calculation of diluted earnings per share utilizing the treasury stock method. On April 30, 2012, 99,108 restricted stock units vested with a vesting date fair value of $0.53 per share. On June 25, 2012, 16,428 restricted stock units were forfeited. There have been no grants of restricted stock units subsequent to the aforementioned grant. Unrecognized compensation cost related the restricted stock units is $116,553 at March 31, 2014.

 

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Note 14— Commitments and Contingencies

 

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us are not possible to reasonably predict, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

 

Environmental and Regulatory

 

As of March 31, 2014, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

 

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Item 2.                                  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Statement Regarding Forward-Looking Information

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to certain risks, uncertainties and assumptions. Certain of these risks are summarized in this report and under “Item 1A. Risk Factors” in our 2013 Annual Report on Form 10-K that we filed with the Securities and Exchange Commission on March 31, 2014, which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

 

You should read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2013, which are included in our 2013 Annual Report on Form 10-K.

 

Overview

 

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. We are primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production is CBM, which is a dry natural gas containing no hydrocarbon liquids. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the central Appalachian Basin in Virginia and West Virginia.

 

The natural gas industry is capital intensive.  Natural gas markets traditionally have been highly volatile.  We have historically made substantial capital expenditures in the exploration, development and acquisition of natural gas reserves.  Our capital expenditures have been financed primarily with internally generated cash flows from operations, bank borrowing and equity raises.

 

Recent Developments

 

On May 12, 2014, we closed the previously announced sale of substantially all of our remaining assets which consisted of coalbed methane interests and other assets located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership.  The purchase price of $107.0 million was adjusted downward $9.5 million to account for cash flows from the effective date to closing, resulting in net proceeds of $97.5 million.  The final adjusted purchase price is to be determined within 95 days of the close of the Asset Sale or by August 15, 2014

 

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the banks party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”).  Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled approximately $69.1. As a result, we satisfied all of our material obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million. 

 

The Asset Purchase Agreement required that all of our employees who accepted employment with the Buyer following the consummation of the Asset Sale first resign their employment with us. Our board of directors adopted a plan of termination effective as of the closing of the Asset Sale, pursuant to which we will terminate all employment agreements, change of control agreements and plans, and benefit plans including its long-term incentive plan, and, in exchange for releases, pay the severance benefits and change of control payments provided for under all of such agreements and plans, including a cash amount in lieu of reimbursement of COBRA premiums, as if all of such employees had been terminated (estimated to total approximately $4 million).  See executive compensation arrangements described below.  We have concluded that we will need to continue to employ various people to provide certain services to the Buyer during the 90-day transition period following the closing of the Asset Sale, and to comply with our public reporting requirements.   These remaining employees, including our named executive officers, will be employed on an at-will basis.

 

The remaining balance of the net proceeds from the Asset Sale totaled approximately $24 million.  These funds will be held by the Company and used for normal working capital and operating expense purposes while we evaluate our next steps. We currently anticipate that the Asset Sale will be followed by either a business combination/merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

 

Executive Compensation Arrangements

 

Effective as of the closing of the Asset Sale, each of Mr. William C. Rankin,  the Company’s President and Chief Executive Officer, Mr. Tony Oviedo, the Company’s Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller, and Mr. Brett S. Camp, the Company’s Senior Vice President – Operations, entered into an (i) Agreement Concerning Termination of Employment Agreement and General Release (the “Severance Agreement”) and (ii) Agreement Concerning Forfeiture of Restricted Stock and Restricted Stock Units under the GeoMet, Inc. 2006 Long-Term Incentive Plan (the “Forfeiture Agreement”). 

 

   William C. Rankin

 

Under the terms of Mr. Rankin’s Severance Agreement, Mr. Rankin and the Company terminated the Amended and Restated Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Rankin’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Rankin an amount equal to (i) $1,024,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Rankin would have received if Mr. Rankin’s employment was

 

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terminated in connection with the Asset Sale), plus (b) $24,391.98 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Rankin was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Rankin in a single lump sum on May 30, 2014.

 

Pursuant to the Severance Agreement, Mr. Rankin’s employment with the Company will continue on an at-will basis, terminable by either Mr. Rankin or the Company for any reason with or without notice.  Mr. Rankin will be a part-time employee and dedicate an average of 20% of his working time to the Company. Mr. Rankin’s base salary following the closing of the Asset Sale is $1,250.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Rankin agreed to release the Company and its affiliates from any and all claims.

 

Pursuant to Mr. Rankin’s Forfeiture Agreement, Mr. Rankin agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Rankin immediately prior to the closing of the Asset Sale.

 

   Tony Oviedo

 

Under the terms of Mr. Oviedo’s Severance Agreement, Mr. Oviedo and the Company terminated the Amended and Restated Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Oviedo’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Oviedo an amount equal to (i) $630,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Oviedo would have received if Mr. Oviedo’s employment was terminated in connection with the Asset Sale), plus (b) $24,391.98 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Oviedo was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Oviedo in a single lump sum on May 30, 2014.

 

Pursuant to the Severance Agreement, Mr. Oviedo’s employment with the Company will continue on an at-will basis, terminable by either Mr. Oviedo or the Company for any reason with or without notice.  Mr. Oviedo will be a full-time employee and dedicate an average of 100% of his working time to the Company. Mr. Oviedo’s base salary following the closing of the Asset Sale is $4,625.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Oviedo agreed to release the Company and its affiliates from any and all claims.

    

Pursuant to Mr. Oviedo’s Forfeiture Agreement, Mr. Oviedo agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Oviedo immediately prior to the closing of the Asset Sale.

 

   Brett S. Camp

 

Under the terms of Mr. Camp’s Severance Agreement, Mr. Camp and the Company terminated the Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Camp’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Camp an amount equal to (i) $630,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Camp would have received if Mr. Camp’s employment was terminated in connection with the Asset Sale), plus (b) $35,070.48 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Camp was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Camp in a single lump sum on May 30, 2014.

 

Pursuant to the Severance Agreement, Mr. Camp’s employment with the Company will continue on an at-will basis, terminable by either Mr. Camp or the Company for any reason with or without notice.  Mr. Camp will be a part-time employee and dedicate an average of 50% of his working time to the Company. Mr. Camp’s base salary following the closing of the Asset Sale is $2,310.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Camp agreed to release the Company and its affiliates from any and all claims.

 

Pursuant to Mr. Camp’s Forfeiture Agreement, Mr. Camp agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Camp immediately prior to the closing of the Asset Sale.

 

Areas of Operation

 

Prior to the closing of the Asset Sale, our core areas of operations were in the Central Appalachian Basin of Virginia and West Virginia. We also previously had operations located in the Black Warrior and Cahaba Basins in Alabama. On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama and, on May 12, 2014, closed the sale of substantially all of our remaining assets which were located in the Central Appalachian Basin of Virginia and West Virginia.

 

Central Appalachia

 

Pond Creek and Lasher Fields—We were the operator of 298 producing vertical CBM wells in which we owned a 99.0% average working interest in the Pond Creek and Lasher fields located in southern West Virginia and southwestern Virginia. Net daily sales of gas averaged 15.3 MMcf per day for the three months ended March 31, 2014. Our natural gas production from the Pond Creek field was delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We had two long-term transportation agreements with ETNG which went into effect in April 2007 with total maximum daily quantities of 15,000 MMBtu’s and 10,000 MMBtu’s and primary terms of 15 years and 10 years, respectively. Our gas from the Lasher field was delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtu’s per day. We also owned and operated a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production was gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system. In addition, we owned and operated a disposal well to dispose of produced water from both the Pond Creek and Lasher fields.

 

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Pinnate Horizontal Wells—We were the operator of 44 producing pinnate horizontal CBM wells in which we owned a 71.6% average working interest in central and northern West Virginia. We also had a 33.7 % average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. Net daily sales of natural gas averaged 6.0 MMcf per day for the three months ended March 31, 2014.  We were party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring through November 2024 which could have been automatically extended at GeoMet’s option at the maximum tariff rate. We were also party to a 10,000 MMBtu per day gathering contract that was in a month-to-month evergreen term.  In some cases, our natural gas sales volumes were delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes were sold at a delivery point into the respective interstate pipeline system utilized.

 

Critical Accounting Policies

 

The preparation of financial statements in conformity with GAAP requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting policies are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. There have been no significant changes to our critical accounting policies during the three months ended March 31, 2014.

 

Natural Gas Production Operations Summary

 

As a result of meeting all of the criteria established under GAAP, we have presented our natural gas operating results as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013. The table below presents information on gas revenues, sales volumes, production expenses and per Mcf data for the three months ended March 31, 2014 and 2013. This table should be read with the discussion of the results of operations for the periods presented below (in thousands, except per Mcf amounts).

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

Gas sales

 

$

9,678

 

$

10,879

 

Lease operating expenses

 

$

2,552

 

$

4,469

 

Compression and transportation expenses

 

1,674

 

1,839

 

Production taxes

 

578

 

550

 

Total production expenses

 

$

4,804

 

$

6,858

 

Net sales volumes (Consolidated) (MMcf)

 

1,916

 

3,108

 

Pond Creek and Lasher fields

 

1,376

 

1,452

 

Pinnate wells (Central Appalachian Basin)

 

540

 

753

 

Gurnee field (Cahaba Basin)

 

 

396

 

Black Warrior Basin fields

 

 

507

 

Per Mcf data ($/Mcf):

 

 

 

 

 

Average natural gas sales price (Consolidated)

 

$

5.05

 

$

3.50

 

Pond Creek and Lasher fields

 

$

5.16

 

$

3.60

 

Pinnate wells (Central Appalachian Basin)

 

$

4.78

 

$

3.40

 

Gurnee field (Cahaba Basin)

 

$

 

$

3.44

 

Black Warrior Basin fields

 

$

 

$

3.43

 

Average natural gas sales price realized (Consolidated)(1)

 

$

4.55

 

$

4.50

 

Lease operating expenses (Consolidated)

 

$

1.33

 

$

1.44

 

Pond Creek and Lasher fields

 

$

1.21

 

$

1.21

 

Pinnate wells (Central Appalachian Basin)

 

$

1.65

 

$

1.68

 

Gurnee field (Cahaba Basin)

 

$

 

$

2.77

 

Black Warrior Basin fields

 

$

 

$

0.67

 

Compression and transportation expenses (Consolidated)

 

$

0.88

 

$

0.59

 

Pond Creek and Lasher fields

 

$

0.61

 

$

0.58

 

Pinnate wells (Central Appalachian Basin)

 

$

1.51

 

$

1.04

 

Gurnee field (Cahaba Basin)

 

$

 

$

0.31

 

Black Warrior Basin fields

 

$

 

$

0.19

 

Production taxes (Consolidated)

 

$

0.30

 

$

0.18

 

Pond Creek and Lasher fields

 

$

0.30

 

$

0.19

 

Pinnate wells (Central Appalachian Basin)

 

$

0.32

 

$

0.15

 

Gurnee field (Cahaba Basin)

 

$

 

$

0.15

 

Black Warrior Basin fields

 

$

 

$

0.20

 

Total production expenses (Consolidated)

 

$

2.51

 

$

2.21

 

Pond Creek and Lasher fields

 

$

2.12

 

$

1.98

 

Pinnate wells (Central Appalachian Basin)

 

$

3.48

 

$

2.87

 

Gurnee field (Cahaba Basin)

 

$

 

$

3.23

 

Black Warrior Basin fields

 

$

 

$

1.06

 

Depletion (Consolidated)

 

$

0.38

 

$

0.47

 

 

19



(1)                  Average natural gas sales price realized includes the effects of realized gains and losses on derivative contracts.

 

Results of Operations

 

Three months ended March 31, 2014 compared with three months ended March 31, 2013

 

The following are selected items derived from our Consolidated Statement of Operations (Unaudited) and their percentage changes from the comparable period are presented below.

 

 

 

Three Months Ended
March 31,

 

 

 

 

 

2014

 

2013

 

Change

 

 

 

(in thousands)

 

Depreciation, depletion and amortization

 

$

114

 

$

34

 

235

%

General and administrative

 

$

1,030

 

$

998

 

3

%

Income (loss) from discontinued operations

 

$

2,017

 

$

(4,617

)

NM

 

Income tax expense

 

$

6

 

$

6

 

NM

 

 

NM-Not Meaningful

 

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $0.08 million, or 235%, to $0.11 million compared to the prior year period. This increase was primarily due to the $0.09 million in accelerated depreciation of certain furniture, fixtures and equipment that are not included in our assets held for sale and now have a decreased useful life.

 

General and administrative. General and administrative expense remained flat when compared to the prior year period.

 

Income (loss) from discontinued operations. Income from discontinued operations increased by $6.6 million to $2.0 million compared to the prior year period. The increase was primarily due to increased natural gas prices from the prior year period.

 

Income tax expense. The income tax expense in the current year period was different than the amount computed using the statutory rate primarily due to a decrease of $0.3 million in the valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:

 

Amount computed using statutory rates

 

$

290,736

 

34.00

%

State income taxes—net of federal benefit

 

36,859

 

4.31

%

Valuation Allowance

 

(343,900

)

-40.22

%

Nondeductible items and other

 

22,555

 

2.64

%

Income tax provision

 

$

6,250

 

0.73

%

 

Liquidity and Capital Resources

 

Cash Flows and Liquidity

 

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Cash flows provided by operations for the three months ended March 31, 2014 were $0.9 million, down $3.9 million from the prior year period. The decrease was primarily due to production volumes lost in the June 2013 sale of our Alabama assets. Cash flows provided by operations of $0.9 million for the three months ended March 31, 2014, as well as the use of $0.7 million in cash on hand were sufficient to fund net cash used in financing activities of $1.6 million, consisting almost entirely of repayments of borrowings under our credit agreement.

 

Closing of Asset Sale

 

On May 12, 2014, we closed the previously announced sale of substantially all of our remaining assets which consisted of coalbed methane interests and other assets located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership.  The purchase price of $107.0 million was adjusted downward $9.5 million to account for cash flows from the effective date to closing, resulting in net proceeds of $97.5 million.  The final adjusted purchase price is to be determined within 95 days of the close of the Asset Sale or by August 15, 2014

 

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Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the banks party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”).  Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled approximately $69.1. As a result, we satisfied all of our material obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.  

 

The Asset Purchase Agreement required that all of our employees who accepted employment with the Buyer following the consummation of the Asset Sale first resign their employment with us. Our board of directors adopted a plan of termination effective as of the closing of the Asset Sale, pursuant to which we will terminate all employment agreements, change of control agreements and plans, and benefit plans including its long-term incentive plan, and, in exchange for releases, pay the severance benefits and change of control payments provided for under all of such agreements and plans, including a cash amount in lieu of reimbursement of COBRA premiums, as if all of such employees had been terminated (estimated to total approximately $4 million).  See Recent Developments – Executive Compensation Arrangements.  We have concluded that we will need to continue to employ various people to provide certain services to the Buyer during the 90-day transition period following the closing of the Asset Sale, and to comply with our public reporting requirements.   These remaining employees, including our named executive officers, will be employed on an at-will basis.

 

The remaining balance of the net proceeds from the Asset Sale is estimated to total approximately $24 million.  These funds will be held by the Company and used for normal working capital and operating expense purposes while we evaluate our next steps. We estimate that operating expenses will be approximately $54,000 per month. We currently anticipate that the Asset Sale will be followed by either a business combination/merger or a dissolution and distribution of our remaining assets in accordance with applicable law. 

 

The terms of our outstanding Preferred Stock provide that in the event of a liquidation or dissolution of the Company, the holders of our Preferred Stock would be entitled to a liquidation preference before the holders of our common stock, par value $0.001 (the “Common Stock”) would be entitled to receive any distributions from the Company.  The liquidation preference is equal to the original investment amount of the Preferred Stock ($40 million) plus paid-in-kind shares plus accrued and unpaid dividends, and currently totals approximately $60 million.  Therefore, if the Company was dissolved as of May 12, 2014, the estimated remaining cash of approximately $24 million would be less than the liquidation preference to which the holders of our Preferred Stock are currently entitled of $60 million.  Absent a concession from the holders of our Preferred Stock, the holders of our Common Stock would not receive any distributions as a result of the Asset Sale or subsequent dissolution of the Company.

 

It is not clear that the terms of our outstanding Preferred Stock would entitle the holders of our Preferred Stock to a liquidation preference in the event the Company was to engage in a business combination/merger.   If our outstanding Preferred Stock is not entitled to a liquidation preference in the event of a business combination/merger, then the Preferred Stock might instead exercise its rights to convert into Common Stock, and then participate with the Common Stock in the proceeds of such transaction on an as-converted basis.  As the estimated remaining cash as of May 12, 2014 is approximately $24 million, this would mean that the holders of our Preferred Stock would receive less in a business combination/merger than the holders of our Preferred Stock would receive in a dissolution as a result of their liquidation preference.  In order for the Company to engage in a business combination/merger, the Company would have to receive the approval of at least fifty percent (50%) of the outstanding shares of Preferred Stock voting separately as a class, in addition to the approval of a majority of the outstanding shares of Common Stock including the outstanding shares of Preferred Stock voting on an as-converted basis treated as a single class.

 

The Company has been advised by the holders of more than fifty percent (50%) of our Preferred Stock that they will not vote in favor of a business combination/merger unless the terms of the transaction provide that the holders of our Preferred Stock will be entitled to receive at least the same value or distributions as such holders would have been entitled to receive in a dissolution pursuant to the liquidation preference to which the holders of the Preferred Stock are entitled.  As a result, absent a concession from the holders of our Preferred Stock, it is likely that the holders of our Common Stock would not receive any distributions if the Asset Sale is followed by a business combination/merger.

 

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Capital Expenditures

 

The following table is a summary of our capital expenditures on an accrual basis by category for the three months ended March 31, 2014 and 2013:

 

 

 

2014

 

2013

 

Capital expenditures:

 

 

 

 

 

Leasehold acquisition

 

$

77,297

 

$

94,266

 

Development

 

(17,410

)

(21,988

)

Other items

 

 

6,037

 

Total capital expenditures

 

$

59,887

 

$

78,315

 

 

We are limited under our credit agreement to incur capital expenditures other than those necessary to maintain current operations and leases of no more than $0.6 million in 2014.

 

Natural Gas Price Risk and Related Hedging Activities

 

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices primarily using derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

 

We have historically entered into hedging transactions, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. Our credit agreement limits amounts of future natural gas production that

 

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we may hedge. At March 31, 2014, we do not have the ability to enter into additional natural gas hedges because we do not have the credit capacity with our existing natural gas hedge counterparties.

 

Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Consolidated Balance Sheets and Consolidated Statements of Operations.

 

Commodity Price Risk and Related Hedging Activities

 

At March 31, 2014, we had the following natural gas collar positions:

 

Period

 

Volume
(MMBtu)

 

Sold
Ceiling

 

Bought
Floor

 

Fair
Value

 

April 2014 through December 2015

 

3,200,000

 

$

4.30

 

$

3.60

 

$

(816,653

)

April 2014 through December 2015

 

3,200,000

 

$

4.20

 

$

3.50

 

(998,908

)

 

 

6,400,000

 

 

 

 

 

$

(1,815,561

)

 

Simultaneously with the closing of the Asset Sale on May 12, 2014, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.

 

Contractual Commitments

 

We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. There has been no material changes in those commitments disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Commitments” of our 2013 Annual Report on Form 10-K that we filed with the SEC on March 31, 2014.

 

Recent Pronouncements

 

In April 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when an entity meets the criteria to be classified as held for sale, the component of an entity or group of components of an entity is disposed of by sale, or the component of an entity or group of components of an entity is disposed of other than by sale. ASU 2014-08 should be applied when any of these occur within annual periods beginning on or after December 15, 2014. Early adoption is permitted, however, the Company elected not to early adopt the ASU. The ASU requires entities to separately present assets and liabilities of a discontinued operation for all periods presented in the balance sheet.  The impact of adoption of the ASU would be the reclassification of all of the assets included in the Asset Sale as Assets held for sale and all related liabilities as Liabilities held for sale, both in the Consolidated Balance Sheet (Unaudited) as of December 31, 2013.

 

Environmental Regulations

 

Our exploration and production operations are subject to significant federal, state, and local environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, quantities, and concentrations of various substances that can be released into the environment as a result of natural gas drilling, production, and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas or that impact protected species; require permits or other governmental authorization before commencing certain activities and require the installation of pollution control measures as a condition of such permits or authorizations; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations are subject to injunctive relief, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that are adopted in the future could have a material adverse impact on our operations.

 

We believe that we are in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws or regulations or the modification of existing laws or regulations could have a material adverse effect on our operations. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend extraordinary resources in order to satisfy existing

 

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applicable environmental laws and regulations. However, costs to comply with existing and any new environmental laws and regulations could become material. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area or in substantial liabilities to third parties. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

 

Item 3.                                  Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk. Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas. Prices received for natural gas are volatile and unpredictable and are beyond our control. For the three months ended March 31, 2014, a 10% decrease in the prices received for natural gas production would have decreased our gas revenues by approximately $0.97 million, which would have been offset by approximately $0.53 million by increased realized gas hedging gains.

 

Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. At March 31, 2014, we had $70.0 million outstanding under our credit agreement. For the three months ended March 31, 2014, interest on the borrowings averaged 4.02% per annum. All of the debt outstanding under our credit agreement accrues interest at floating or market rates. Fluctuations in market interest rates will cause our interest costs to fluctuate. Based upon the weighted average balance outstanding under our credit agreement, a 1% increase in market interest rates would have increased interest expense and negatively impacted our cash flows for the three months ended March 31, 2014 by approximately $0.18 million.

 

Item 4.                                  Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

In accordance with Securities Exchange Act of 1934 (the Exchange Act”) Rules 13a-15(e) and 15d-15(e), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2014 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

Changes in Internal Control Over Financial Reporting

 

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Part II. OTHER INFORMATION

 

Item 1.                                   Legal Proceedings

 

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

 

Environmental and Regulatory

 

As of March 31, 2014, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

 

Item 1A.                         Risk Factors

 

There has been no changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2013.

 

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Item 5.                                   Other Information.

 

We are disclosing in this Item 5 on Form 10-Q the following information in lieu of disclosing such information under the corresponding item number in a Current Report on Form 8-K:

 

Item 1.02.  Termination of a Material Definitive Agreement.

 

On May 12, 2014, the Company, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the financial institutions party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among the Company, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”).  Immediately prior to termination of the Credit Agreement, the Company repaid all amounts owed to the lenders party to the Credit Agreement. As a result, the Company satisfied all of its material obligations under the Credit Agreement. The Company was not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

 

Item 2.05. Costs Associated with Exit or Disposal Activities.

 

The Asset Purchase Agreement required that all of our employees who accepted employment with the Buyer following the consummation of the Asset Sale first resign their employment with us. Our board of directors adopted a plan of termination effective as of the closing of the Asset Sale, pursuant to which we will terminate all employment agreements, change of control agreements and plans, and benefit plans including its long-term incentive plan, and, in exchange for releases, pay the severance benefits and change of control payments provided for under all of such agreements and plans, including a cash amount in lieu of reimbursement of COBRA premiums, as if all of such employees had been terminated. We have concluded that we will need to continue to employ various people to provide certain services to the Buyer during the 90-day transition period following the closing of the Asset Sale, and to comply with our public reporting requirements. These remaining employees, including our named executive officers, will be employed on an at-will basis.

 

The completion date for the above-described plan is currently estimated to be August 31, 2014. The aggregate cost associated with the plan is estimated to be $4.0 million, which includes $3.5 million related to employment agreements, $0.2 related to change of control agreements and plans, and $0.3 related to reimbursement of COBRA premiums. Additionally, the Company expects to pay approximately $0.8 million in connection with the termination of its office leases.

 

Item 5.02.  Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

 

Effective as of the closing of the Asset Sale, each of Mr. William C. Rankin,  the Company’s President and Chief Executive Officer, Mr. Tony Oviedo, the Company’s Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller, and Mr. Brett S. Camp, the Company’s Senior Vice President — Operations, entered into an (i) Agreement Concerning Termination of Employment Agreement and General Release (the “Severance Agreement”) and (ii) Agreement Concerning Forfeiture of Restricted Stock and Restricted Stock Units under the GeoMet, Inc. 2006 Long-Term Incentive Plan (the “Forfeiture Agreement”).

 

William C. Rankin

 

Under the terms of Mr. Rankin’s Severance Agreement, Mr. Rankin and the Company terminated the Amended and Restated Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Rankin’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Rankin an amount equal to (i) $1,024,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Rankin would have received if Mr. Rankin’s employment was terminated in connection with the Asset Sale), plus (b) $24,391.98 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Rankin was to become entitled to such

 

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benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Rankin in a single lump sum on May 31, 2014.

 

Pursuant to the Severance Agreement, Mr. Rankin’s employment with the Company will continue on an at-will basis, terminable by either Mr. Rankin or the Company for any reason with or without notice.  Mr. Rankin will be a part-time employee and dedicate an average of 20% of his working time to the Company. Mr. Rankin’s base salary following the closing of the Asset Sale is $1,250.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Rankin agreed to release the Company and its affiliates from any and all claims.

 

Pursuant to Mr. Rankin’s Forfeiture Agreement, Mr. Rankin agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Rankin immediately prior to the closing of the Asset Sale.

 

Tony Oviedo

 

Under the terms of Mr. Oviedo’s Severance Agreement, Mr. Oviedo and the Company terminated the Amended and Restated Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Oviedo’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Oviedo an amount equal to (i) $630,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Oviedo would have received if Mr. Oviedo’s employment was terminated in connection with the Asset Sale), plus (b) $24,391.98 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Oviedo was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Oviedo in a single lump sum on May 31, 2014.

 

Pursuant to the Severance Agreement, Mr. Oviedo’s employment with the Company will continue on an at-will basis, terminable by either Mr. Oviedo or the Company for any reason with or without notice.  Mr. Oviedo will be a full-time employee and dedicate an average of 100% of his working time to the Company. Mr. Oviedo’s base salary following the closing of the Asset Sale is $4,625.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Oviedo agreed to release the Company and its affiliates from any and all claims.

 

Pursuant to Mr. Oviedo’s Forfeiture Agreement, Mr. Oviedo agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Oviedo immediately prior to the closing of the Asset Sale.

 

Brett S. Camp

 

Under the terms of Mr. Camp’s Severance Agreement, Mr. Camp and the Company terminated the Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Camp’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Camp an amount equal to (i) $630,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Camp would have received if Mr. Camp’s employment was terminated in connection with the Asset Sale), plus (b) $35,070.48 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Camp was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Camp in a single lump sum on May 31, 2014.

 

Pursuant to the Severance Agreement, Mr. Camp’s employment with the Company will continue on an at-will basis, terminable by either Mr. Camp or the Company for any reason with or without notice.  Mr. Camp will be a part-time employee and dedicate an average of 50% of his working time to the Company. Mr. Camp’s base salary following the closing of the Asset Sale is $2,310.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Camp agreed to release the Company and its affiliates from any and all claims.

 

Pursuant to Mr. Camp’s Forfeiture Agreement, Mr. Camp agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Camp immediately prior to the closing of the Asset Sale.

 

Item 6.                                  Exhibits

 

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

 

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SIGNATURES

 

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

 

 

GeoMet, Inc.

 

 

 

 

 

 

Date: May 13, 2014

By

/S/ TONY OVIEDO

 

 

Tony Oviedo, Senior Vice President, Chief Financial Officer,
Chief Accounting Officer and Controller

 

 

(Principal Financial Officer)

 

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INDEX TO EXHIBITS

 

Exhibit
Number

 

Exhibits

 

 

 

3.1

 

Amended and Restated Certificate of Incorporation of GeoMet, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on July 25, 2006 (Registration No. 333-131716)).

 

 

 

3.2

 

Certificate of Designations of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share, of GeoMet, Inc. (incorporated herein by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed on June 24, 2010).

 

 

 

3.3

 

Certificate of Amendment to the Certificate of Designations of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share, of GeoMet, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on December 28, 2010).

 

 

 

3.4

 

Amended and Restated Bylaws of GeoMet, Inc. (Adopted as of September 14, 2010) (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 20, 2010).

 

 

 

10.1*

 

Agreement Concerning Termination Of Employment Agreement And General Release effective as of May 12, 2014 between GeoMet, Inc. and William C. Rankin.

 

 

 

10.2*

 

Agreement Concerning Termination Of Employment Agreement And General Release effective as of May 12, 2014 between GeoMet, Inc. and Tony Oviedo.

 

 

 

10.3*

 

Agreement Concerning Termination Of Employment Agreement And General Release effective as of May 12, 2014 between GeoMet, Inc. and Brett S. Camp.

 

 

 

10.4*

 

Agreement Concerning Forfeiture of Restricted Stock and Restricted Stock Units Under the GeoMet, Inc. 2006 Long-Term Incentive Plan dated effective as of May 12, 2014 between GeoMet, Inc. and William C. Rankin.

 

 

 

10.5*

 

Agreement Concerning Forfeiture of Restricted Stock and Restricted Stock Units Under the GeoMet, Inc. 2006 Long-Term Incentive Plan dated effective as of May 12, 2014 between GeoMet, Inc. and Tony Oviedo.

 

 

 

10.6*

 

Agreement Concerning Forfeiture of Restricted Stock and Restricted Stock Units Under the GeoMet, Inc. 2006 Long-Term Incentive Plan dated effective as of May 12, 2014 between GeoMet, Inc. and Brett S. Camp.

 

 

 

31.1*

 

Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

 

 

 

31.2*

 

Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

 

 

 

32*

 

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

 

 

 

101**

 

Interactive Data Files.

 


*                   Attached hereto.

**            Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.

 

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