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 September 30, 2013

 

OR

 

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

 

For the transition period from              to              

 

Commission File Number 001-32960

 


 

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 October 1, 2013, 40,662,749 shares and 5,818,807 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 September 30, 2013 and December 31, 2012

3

 

Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012

4

 

Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2013 and 2012

5

 

Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012

6

 

Notes to Consolidated Financial Statements (Unaudited)

7

 

 

 

Item 2.

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

20

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

31

 

 

 

Item 4.

Controls and Procedures

31

 

 

 

Part II. Other Information

 

 

 

 

Item 1.

Legal Proceedings

32

 

 

 

Item 1A.

Risk Factors

32

 

 

 

Item 6.

Exhibits

32

 

2



Table of Contents

 

Part I. FINANCIAL INFORMATION

 

Item  1.                                Financial Statements

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Balance Sheets (Unaudited)

 

 

 

September 30,
2013

 

December 31, 2012

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

9,704,630

 

$

7,234,225

 

Accounts receivable, net of allowance of $14,744 and $17,634 at September 30, 2013 and December 31, 2012, respectively

 

2,613,257

 

6,248,819

 

Inventory

 

 

262,885

 

Derivative asset—natural gas contracts

 

371,025

 

3,929,767

 

Other current assets

 

941,331

 

1,437,819

 

Total current assets

 

13,630,243

 

19,113,515

 

Gas properties—utilizing the full cost method of accounting:

 

 

 

 

 

Proved gas properties

 

333,396,454

 

539,077,119

 

Other property and equipment

 

3,294,083

 

3,749,621

 

Total property and equipment

 

336,690,537

 

542,826,740

 

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

 

(293,173,690

)

(467,702,053

)

Property and equipment—net

 

43,516,847

 

75,124,687

 

Other noncurrent assets:

 

 

 

 

 

Deferred income taxes

 

105,733

 

1,125,804

 

Other

 

1,100,268

 

962,451

 

Total other noncurrent assets

 

1,206,001

 

2,088,255

 

TOTAL ASSETS

 

$

58,353,091

 

$

96,326,457

 

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable

 

$

3,146,338

 

$

5,728,879

 

Royalties payable

 

3,622,600

 

3,830,904

 

Accrued liabilities

 

913,335

 

1,793,946

 

Deferred income taxes

 

105,733

 

1,125,804

 

Derivative liability—natural gas contracts

 

 

919,572

 

Asset retirement obligations

 

180,183

 

73,706

 

Current portion of long-term debt

 

74,000,000

 

10,300,000

 

Total current liabilities

 

81,968,189

 

23,772,811

 

Long-term debt

 

 

129,000,000

 

Asset retirement obligations

 

9,490,684

 

13,235,318

 

Derivative liability—natural gas contracts

 

571,386

 

1,636,348

 

Other long-term accrued liabilities

 

120,996

 

143,682

 

TOTAL LIABILITIES

 

92,151,255

 

167,788,159

 

Commitments and contingencies (Note 16)

 

 

 

 

 

Mezzanine equity:

 

 

 

 

 

Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,435; redemption amount $58,188,070; $.001 par value; 7,401,832 shares authorized, 5,818,807 and 5,305,865 shares were issued and outstanding at September 30, 2013 and December 31, 2012, respectively

 

41,197,933

 

35,851,887

 

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; 40,662,749 and 40,690,077 issued and outstanding at September 30, 2013 and December 31, 2012, respectively

 

40,663

 

40,690

 

Treasury stock—10,432 shares at September 30, 2013 and December 31, 2012

 

(94,424

)

(94,424

)

Paid-in capital

 

189,690,990

 

195,033,585

 

Accumulated other comprehensive loss

 

(22,233

)

(53,020

)

Retained deficit

 

(264,611,093

)

(302,057,496

)

Less notes receivable

 

 

(182,924

)

Total stockholders’ deficit

 

(74,996,097

)

(107,313,589

)

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT

 

$

58,353,091

 

$

96,326,457

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

3



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Statements of Operations

(Unaudited)

 

 

 

Three Months Ended September 30,

 

Nine months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Revenues:

 

 

 

 

 

 

 

 

 

Gas sales

 

$

7,391,747

 

$

9,609,586

 

$

30,324,181

 

$

27,464,729

 

Operating fees

 

21,325

 

55,439

 

104,394

 

190,650

 

Total revenues

 

7,413,072

 

9,665,025

 

30,428,575

 

27,655,379

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

2,022,962

 

4,417,390

 

10,615,069

 

13,350,417

 

Compression and transportation expense

 

1,778,752

 

2,217,610

 

5,485,553

 

6,757,864

 

Production taxes

 

419,332

 

442,129

 

1,617,249

 

1,276,215

 

Depreciation, depletion and amortization

 

869,787

 

2,539,531

 

3,746,930

 

9,460,420

 

Impairment of gas properties

 

 

25,431,734

 

 

83,467,022

 

General and administrative

 

1,049,372

 

1,097,308

 

3,456,126

 

3,765,475

 

Restructuring costs

 

6,000

 

187,597

 

93,584

 

952,830

 

(Gains) losses on natural gas derivatives

 

(625,328

)

4,783,942

 

760,142

 

(341,525

)

Total operating expenses

 

5,520,877

 

41,117,241

 

25,774,653

 

118,688,718

 

 

 

 

 

 

 

 

 

 

 

(Loss) gain on the sale of Properties in Alabama

 

(187,298

)

 

36,948,313

 

 

 

 

 

 

 

 

 

 

 

 

Operating income (loss)

 

1,704,897

 

(31,452,216

)

41,602,235

 

(91,033,339

)

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest income

 

432

 

814

 

1,280

 

5,113

 

Interest expense

 

(857,847

)

(1,513,684

)

(4,093,452

)

(4,057,927

)

Write off of debt issuance costs

 

 

(1,377,520

)

 

(1,377,520

)

Other

 

(9,564

)

943

 

(44,910

)

(3,156

)

Total other income (expense):

 

(866,979

)

(2,889,447

)

(4,137,082

)

(5,433,490

)

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes from continuing operations

 

837,918

 

(34,341,663

)

37,465,153

 

(96,466,829

)

Income tax expense

 

(6,250

)

(6,250

)

(18,750

)

(44,036,950

)

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

831,668

 

(34,347,913

)

37,446,403

 

(140,503,779

)

Discontinued operations, net of tax

 

 

(25,655

)

 

(722,036

)

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

831,668

 

$

(34,373,568

)

$

37,446,403

 

$

(141,225,815

)

Accretion of Series A Convertible Redeemable Preferred Stock

 

(598,611

)

(485,338

)

(1,624,984

)

(1,418,307

)

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

 

(1,277,889

)

(903,912

)

(3,721,062

)

(2,764,257

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(634

)

(689

)

(1,835

)

(1,985

)

Net (loss) income available to common stockholders

 

$

(1,045,466

)

$

(35,763,507

)

$

32,098,522

 

$

(145,410,364

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—basic:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.03

)

$

(0.89

)

$

0.79

 

$

(3.61

)

Net loss per common share from discontinued operations

 

 

 

 

(0.02

)

Net (loss) income per common share—basic

 

$

(0.03

)

$

(0.89

)

$

0.79

 

$

(3.63

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—diluted:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.03

)

$

(0.89

)

$

0.45

 

$

(3.61

)

Net loss per common share from discontinued operations

 

 

 

 

(0.02

)

Net (loss) income per common share—diluted

 

$

(0.03

)

$

(0.89

)

$

0.45

 

$

(3.63

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares:

 

 

 

 

 

 

 

 

 

Basic

 

40,485,875

 

40,286,573

 

40,473,460

 

40,018,778

 

Diluted

 

40,485,875

 

40,286,573

 

82,707,070

 

40,018,778

 

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

4



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

 

 

 

Three Months Ended September 30,

 

Nine months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Net income (loss)

 

$

831,668

 

$

(34,373,568

)

$

37,446,403

 

$

(141,225,815

)

Gain on foreign currency translation adjustment

 

45,198

 

14,240

 

36,080

 

2,019

 

Reclassification adjustment for loss on foreign currency translation included in net loss

 

 

 

 

1,307,906

 

Unrealized (loss) gain on available for sale securities

 

35,116

 

(19,454

)

(5,293

)

31,738

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss)

 

$

911,982

 

$

(34,378,782

)

$

37,477,190

 

$

(139,884,152

)

 

See accompanying Notes to Consolidated Financial Statements (Unaudited)

 

5



Table of Contents

 

GEOMET, INC. AND SUBSIDIARIES

 

Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

Nine months Ended September 30,

 

 

 

2013

 

2012

 

Cash flows provided by operating activities:

 

 

 

 

 

Net income (loss)

 

$

37,446,403

 

$

(141,225,815

)

Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

3,746,930

 

9,458,700

 

Impairment of gas properties

 

 

83,467,022

 

Amortization of debt issuance costs

 

685,422

 

530,799

 

Write off of debt issuance costs

 

 

1,377,520

 

Deferred income tax expense

 

 

44,018,200

 

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

 

1,574,208

 

13,258,958

 

Stock-based compensation

 

188,209

 

512,377

 

Gain on the sale of Properties in Alabama

 

(36,948,313

)

 

Loss on sale of Hudson’s Hope Gas, Ltd.

 

 

683,154

 

Loss on sale of other assets

 

53,366

 

5,200

 

Accretion expense—asset retirement obligation

 

822,601

 

584,813

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

4,019,863

 

(13,052

)

Other assets

 

(419,572

)

193,953

 

Accounts payable

 

(2,724,252

)

1,577,480

 

Other accrued liabilities

 

(840,525

)

(833,930

)

 

 

 

 

 

 

Net cash provided by operating activities

 

7,604,340

 

13,595,379

 

 

 

 

 

 

 

Cash flows provided by investing activities:

 

 

 

 

 

Capital expenditures

 

(580,323

)

(856,655

)

Return of original basis through the settlement of natural gas derivative contracts

 

 

7,147,696

 

Net proceeds from the sale of Properties in Alabama

 

60,732,775

 

 

Proceeds from sale of other property and equipment

 

19,276

 

3,500

 

 

 

 

 

 

 

Net cash provided by investing activities

 

60,171,728

 

6,294,541

 

 

 

 

 

 

 

Cash flows used in financing activities:

 

 

 

 

 

Proceeds from revolving credit facility borrowings

 

 

10,500,000

 

Payments on revolving credit facility

 

(65,300,000

)

(22,800,000

)

Deferred financing costs

 

(3,801

)

(853,578

)

Payments on other debt

 

 

(188,965

)

Purchase and cancellation of treasury stock

 

(27

)

(2,039

)

Cash dividends paid on Series A Convertible Redeemable Preferred Stock

 

(1,835

)

(1,985

)

 

 

 

 

 

 

Net cash used in financing activities

 

(65,305,663

)

(13,346,567

)

Effect of exchange rate changes on cash

 

 

5,115

 

 

 

 

 

 

 

Increase in cash and cash equivalents

 

2,470,405

 

6,548,468

 

Cash and cash equivalents at beginning of period

 

7,234,225

 

457,865

 

 

 

 

 

 

 

Cash and cash equivalents at end of period

 

$

9,704,630

 

$

7,006,333

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid during the period for interest expense

 

$

4,169,622

 

$

5,960,054

 

 

 

 

 

 

 

Cash paid during the period for income taxes

 

$

18,750

 

$

18,750

 

 

 

 

 

 

 

Significant noncash investing and financing activities:

 

 

 

 

 

Accrued capital expenditures

 

$

30,380

 

$

609,017

 

Fair value of common stock received in exchange for Hudson’s Hope Gas, Ltd.

 

$

 

$

293,769

 

 

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. Subsequent to the asset sale discussed in Note 2— Sale of Coalbed Methane Properties in Alabama, our core area of operations is the Central Appalachian Basin of Virginia and West Virginia. We also own additional coalbed methane development rights, principally 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, 2012 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 28, 2013.

 

Note 2— Sale of Coalbed Methane Properties in Alabama

 

On June 14, 2013, the Company closed the sale of all of its coal bed methane properties located in the state of Alabama. The sale resulted in proceeds of approximately $62.0 million after purchase price adjustments of $1.2 million to account for net cash flows from the effective date to the closing date. Simultaneously with the close of the property sale, approximately $57.0 million was used to repay outstanding borrowings under the Company’s Credit Agreement and $5.0 million was held in reserve to pay transaction related costs and expenses, including the liquidation of certain natural gas hedge positions. After this repayment, borrowings outstanding under the Credit Agreement totaled $77.0 million. In connection with this repayment the Company no longer has a borrowing base deficiency under the Credit Agreement. The next scheduled borrowing base determination is expected to occur on or around December 15, 2013 and will be based on the Company’s reserves at June 30, 2013. The Credit Agreement continues to have a maturity date of April 1, 2014.

 

GeoMet’s net interest in the properties sold produced approximately 9,700 Mcf of natural gas per day during the month of March 2013 (the effective date of the sale was April 1, 2013), or approximately 29% of GeoMet’s total production for this time period. As of April 1, 2013 and based on SEC guidelines, GeoMet’s net proved reserves attributable to the coalbed methane properties in Alabama being sold were estimated to be approximately 43 Bcf, all classified as proved developed reserves.

 

Total gain on the sale included the following:

 

Cash proceeds

 

$

62,007,639

 

Buyer’s assumption of asset retirement obligations

 

4,411,201

 

Buyer’s assumption of other liabilities

 

164,108

 

Net book value of sold gas properties

 

(27,998,835

)

Net book value of sold inventory

 

(133,732

)

Net book value of sold equipment

 

(108,642

)

Transaction costs

 

(1,120,654

)

Post-closing purchase price adjustments (1)

 

(272,772

)

Total gain on sale

 

$

36,948,313

 

 


(1)                  Post-closing purchase price adjustments results from actual operating revenues and expenses realized related to properties sold that differed from the amounts estimated at the time of closing.

 

7



Table of Contents

 

No current federal or state income taxes payable were recorded in conjunction with the sale of the Alabama properties which is the result of 2013 tax basis operating losses generated in the normal course of business that are estimated to be available to offset the taxable gain. Additionally, our net deferred tax asset and the offsetting valuation allowance recorded against it were both reduced by $14.1 million as a result of recording the gain on the sale of assets. At September 30, 2013, the remaining net deferred tax asset is $82.5 million for which a full valuation allowance remains recorded against it.

 

Pro forma adjustments related to the unaudited pro forma financial information presented below were computed assuming the transaction was consummated on January 1, 2012 and include adjustments which give effect to events that are (i) directly attributable to the transaction, (ii) expected to have a continuing impact on the Company, and (iii) factually supportable. As such, included in Net income (loss), Net (loss) income available to common stockholders and Net (loss) income per common share (basic and diluted) is the total gain on sale of $36,948,313.

 

Consolidated Pro Forma Information

 

 

 

Three Months Ended September 30,

 

Nine months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Revenue

 

$

7,415,443

 

$

6,679,319

 

$

24,186,419

 

$

19,215,088

 

Income (loss) from continuing operations

 

$

1,705,427

 

$

(25,432,968

)

$

38,801,724

 

$

(66,600,078

)

Net income (loss)

 

$

1,302,969

 

$

(26,473,538

)

$

36,363,683

 

$

(114,527,415

)

Net (loss) income available to common stockholders

 

$

(574,165

)

$

(27,863,477

)

$

31,015,802

 

$

(118,711,964

)

Net (loss) income per common share—basic

 

$

(0.01

)

$

(0.69

)

$

0.77

 

$

(2.99

)

Net (loss) income per common share—diluted

 

$

(0.01

)

$

(0.69

)

$

0.44

 

$

(2.99

)

 

Note 3— Going Concern and Management’s Plans

 

We previously disclosed our engagement of FBR Capital Markets & Co. to assist the Company in exploring strategic alternatives. We have concluded that process, and have engaged Lantana Oil & Gas Partners to assist us in pursuing the possible sale of all or substantially all of our assets.

 

We currently anticipate that any such sale transaction would be followed by either a merger or a liquidation and distribution of our remaining assets in accordance with applicable law.  Generally, in a dissolution, the net proceeds of a sale would be used to repay the amount outstanding under our Credit Agreement and make adequate provision for satisfaction of other known or contingent payment obligations. Remaining assets, if any, would first be used to satisfy all or a portion of the liquidation preference of our outstanding Preferred Stock, then, if any assets remained, be made available for distribution to the holders of our common stock.

 

Any such sale of assets, and any subsequent merger or liquidation, would require approval by (i) our board of directors, (ii) the holders of a majority of our Preferred Stock (voting separately as a class), and (iii) the holders of a majority of our outstanding shares with holders of the Preferred Stock voting with the common stock on an as-converted basis. On an as-converted basis, the Preferred Stock currently represents approximately 52% of the outstanding shares and therefore would have the ability to control any vote requiring the approval of our shareholders, including a vote to approve a sale transaction and any subsequent merger or liquidation.

 

No assurance can be given that a suitable proposal for the sale of all or substantially all of our assets will be presented, that any sale transaction will be consummated, or the terms or structure of any transaction if such a sale transaction is consummated.

 

Although our recent sale of assets brought us into conformity with the borrowing base under our Credit Agreement, we remain highly leveraged.  In addition, our Credit Agreement matures on April 1, 2014, and no assurances can be made that we will be able to refinance, repay or further extend the maturity date of the Credit Agreement.  Also, as of September 30, 2013, we had a working capital deficit of $68.3 million, a retained deficit of $264.6 million and stockholders’ deficit of $75.0 million.  Depressed natural gas prices in 2012 resulted in significant property impairments and full valuation of our deferred tax assets during 2012. On April 2, 2013, all the indebtedness under our Credit Agreement was reclassified to current liabilities.  In addition, our Preferred Stock continues to accrue a dividend of 12.5% per annum, which we have been paying through the issuance of additional shares of Preferred Stock.  Beginning in September 2015, dividends on the Preferred Stock will accrue at 9.6% per annum and be payable in cash.

 

These and other factors raise substantial doubt about the Company’s ability to continue as a going concern for the next twelve months. The accompanying consolidated financial statements (unaudited) have been prepared in conformity with accounting principles generally accepted in the United States which contemplate continuation of the Company as a going concern.

 

In the event the assumption of the continuation of the Company as a going concern was no longer appropriate, the Company would implement the liquidation basis of accounting. Under the liquidation basis of accounting, the carrying amounts of assets as of the date of the authorization of a plan for liquidation, would be adjusted to their estimated net realizable values and liabilities, including the estimated costs associated with implementing a plan for liquidation, would be stated at their estimated settlement amounts.

 

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Note 4—Recent Pronouncements

 

In July 2013, the FASB issued ASU No. 2013-10, Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. The amendments in ASU 2013-10 permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to UST and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We are presently assessing the potential impact of ASU 2013-11.

 

In March 2013, the FASB issued ASU 2013-07, “Presentation of Financial Statements (Topic 205): Liquidation Basis of Accounting.” The amendments require an entity to prepare its financial statements using the liquidation basis of accounting when liquidation is imminent. Liquidation is imminent when the likelihood is remote that the entity will return from liquidation and either (a) a plan for liquidation is approved by the person or persons with the authority to make such a plan effective and the likelihood is remote that the execution of the plan will be blocked by other parties or (b) a plan for liquidation is being imposed by other forces (for example, involuntary bankruptcy). If a plan for liquidation was specified in the entity’s governing documents from the entity’s inception (for example, limited-life entities), the entity should apply the liquidation basis of accounting only if the approved plan for liquidation differs from the plan for liquidation that was specified at the entity’s inception. The amendments require financial statements prepared using the liquidation basis of accounting to present relevant information about an entity’s expected resources in liquidation by measuring and presenting assets at the amount of the expected cash proceeds from liquidation. The entity should include in its presentation of assets any items it had not previously recognized under U.S. GAAP but that it expects to either sell in liquidation or use in settling liabilities (for example, trademarks). The amendments are effective for entities that determine liquidation is imminent during annual reporting periods beginning after December 15, 2013, and interim reporting periods therein. Entities should apply the requirements prospectively from the day that liquidation becomes imminent. Early adoption is permitted.

 

In February 2013, the FASB issued ASU No. 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations addressed within existing guidance. The update is effective for interim and annual periods beginning after December 15, 2013 and is required to be applied retrospectively to all prior periods presented for those obligations that existed upon adoption of ASU 2013-04. We are presently assessing the potential impact of ASU 2013-04.

 

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. The update requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under accounting principles generally accepted in the United States (“GAAP”) to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The amendments are effective prospectively for reporting periods beginning after December 15, 2012. The Company has adopted and applied the provisions of ASU 2012-02 which did not impact its operating results, financial position or cash flows.

 

In January 2013, the FASB issued ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” The amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. The Company has adopted and applied the provisions of ASU 2013-01. See disclosure provided in Note 9—Derivative Instruments and Hedging Activities.

 

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Note 5—Net (Loss) Income Per Common Share

 

Net (loss) income per common share—basic is calculated by dividing Net (loss) income available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net (loss) income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net (loss) income available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net (loss) income 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 common shares would have an anti-dilutive effect. A reconciliation of Net (loss) income per common share is as follows:

 

 

 

Three Months Ended September 30,

 

Nine months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Net (loss) income available to common stockholders—basic

 

$

(1,045,466

)

$

(35,763,507

)

$

32,098,522

 

$

(145,410,364

)

Dilutive related add back:

 

 

 

 

 

 

 

 

 

Accretion of Preferred Stock

 

 

 

1,624,984

 

 

Paid-in-kind dividends on Preferred Stock

 

 

 

3,721,062

 

 

Cash dividends paid on Preferred Stock

 

 

 

1,835

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income available to common stockholders—diluted

 

$

(1,045,466

)

$

(35,763,507

)

$

37,446,403

 

$

(145,410,364

)

Net (loss) income per common share—basic:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.03

)

$

(0.89

)

$

0.79

 

$

(3.61

)

Net loss per common share from discontinued operations

 

 

 

 

(0.02

)

Net (loss) income per common share—basic

 

$

(0.03

)

$

(0.89

)

$

0.79

 

$

(3.63

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share—diluted:

 

 

 

 

 

 

 

 

 

Net (loss) income per common share from continuing operations

 

$

(0.03

)

$

(0.89

)

$

0.45

 

$

(3.61

)

Net loss per common share from discontinued operations

 

 

 

 

(0.02

)

Net (loss) income per common share—diluted

 

$

(0.03

)

$

(0.89

)

$

0.45

 

$

(3.63

)

Weighted average number of common shares:

 

 

 

 

 

 

 

 

 

Basic

 

40,485,875

 

40,286,573

 

40,473,460

 

40,018,778

 

Potentially dilutive securities:

 

 

 

 

 

 

 

 

 

Preferred stock

 

 

 

42,117,057

 

 

Restricted stock units

 

 

 

116,553

 

 

Diluted

 

40,485,875

 

40,286,573

 

82,707,070

 

40,018,778

 

 

Net income per common share—basic for the nine months ended September 30, 2013 included $0.91 per common share, net of $0 tax, resulting solely from the Gain on the sale of Properties in Alabama. Net income per common share—diluted for the nine months ended September 30, 2013 included $0.45 per common share, net of $0 tax, resulting from the Gain on the sale of Properties in Alabama.

 

Net loss per common share—diluted for the three months ended September 30, 2013 excluded the effect of outstanding options exercisable to purchase 1,591,920 shares, 116,553 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 176,935 weighted average restricted shares outstanding, and 5,644,456 weighted average shares of Series A Convertible Redeemable Preferred Stock (43,418,898 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

 

Net income per common share—diluted for the nine months ended September 30, 2013 excluded the effect of outstanding exercisable options to purchase 1,591,920 shares and 204,833 weighted average restricted shares outstanding because they were assumed reacquired under the treasury stock method.

 

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Table of Contents

 

Net loss per common share—diluted for the three months ended September 30, 2012 excluded the effect of outstanding options exercisable to purchase 2,397,603 shares, 116,732 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 273,301 weighted average restricted shares outstanding, and 4,838,181 weighted average shares of Series A Convertible Redeemable Preferred Stock (37,216,776 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

 

Net loss per common share—diluted for the nine months ended September 30, 2012 excluded the effect of outstanding options exercisable to purchase 2,397,603 shares, 170,570 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 262,896 weighted average restricted shares outstanding, and 4,549,537 weighted average shares of Series A Convertible Redeemable Preferred Stock (34,996,440 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

 

Note 6—Discontinued Operations

 

On June 20, 2012, we disposed of Hudson’s Hope Gas, Ltd., a subsidiary which held our Canadian gas properties, in exchange for two million shares of Canada Energy Partners, Inc. (“CEP Shares”) which were restricted from being sold before June 20, 2013. We recognized a loss on the disposition in the amount of $0.7 million, which was made up of a $1.3 million loss related to the currency translation adjustment, offset by $0.3 million in asset retirement obligations conveyed to the buyer and the proceeds consisting of the $0.3 million in estimated fair value of the CEP shares received. The loss on this disposition has been included in Discontinued operations, net of tax, in the Consolidated Statements of Operations (Unaudited). Additionally, all historical operating results related to the disposed company have been removed from Operating (loss) income and included in Discontinued operations, net of tax, in the Consolidated Statements of Operations (Unaudited) for the periods presented.

 

As a result of the disposition, we are classifying these activities as a discontinued operation for all the periods presented. Results for activities reported as discontinued operations for the three and nine months ended September 30, 2013 and 2012 were as follows:

 

 

 

Three Months Ended September 30,

 

Nine months Ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Revenues

 

$

 

$

 

$

 

$

 

Total operating benefit (expenses)

 

 

 

 

(13,123

)

 

 

 

 

 

 

 

 

 

 

Operating income (loss)

 

 

 

 

(13,123

)

Loss on sale of Hudson’s Hope, Ltd.

 

 

 

 

(683,154

)

Other income (expense)

 

 

(25,655

)

 

(25,759

)

Income tax expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

 

$

(25,655

)

$

 

$

(722,036

)

 

Note 7—Gas Properties

 

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

 

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Table of Contents

 

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 September 30, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.62 per Mcf, resulting in a natural gas price of $3.68 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 September 30, 2013.

 

For the twelve months ended September 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $2.84 per Mcf, resulting in a natural gas price of $2.99 per Mcf when adjusted for regional price differentials. For the three and nine months ended September 30, 2012, we recorded a $25.4 million and $83.5 million write-down, respectively, of the carrying value of our U.S. full cost pool.

 

In accordance with the full cost method of accounting for gas properties as prescribed by the SEC, sales of oil and gas reserves in place are generally accounted for as adjustments of capitalized cost, with no gain or loss recognized, unless such adjustments significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center (i.e. depletion rate).  A significant alteration would not ordinarily be expected to occur for sales involving less than 25 percent of the reserve quantities of a given cost center.  The sale of the Alabama gas properties, as disclosed in Note 2— Sale of Coalbed Methane Properties in Alabama, would have significantly altered the depletion rate. As such, a gain on the sale was recorded in the Consolidated Statements of Operations for the three and nine months ended September 30, 2013.

 

Note 8—Asset Retirement Liability

 

We record an asset retirement obligation (“ARO”) on 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 we incurred the abandonment obligation using an assumed interest rate. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed interest rate.

 

The following table details the changes to our asset retirement liability for the nine months ended September 30, 2013:

 

Current portion of liability at January 1, 2013

 

$

73,706

 

Add: Long-term asset retirement liability at January 1, 2013

 

13,235,318

 

Asset retirement liability at January 1, 2013

 

13,309,024

 

Buyer’s assumption of asset retirement obligations

 

(4,411,201

)

Revision of estimates

 

103,287

 

Settlements

 

(152,844

)

Accretion

 

822,601

 

Asset retirement liability at September 30, 2013

 

9,670,867

 

Less: Current portion of liability

 

(180,183

)

Long-term asset retirement liability

 

$

9,490,684

 

 

Note 9—Derivative Instruments and 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. At September 30, 2013, 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.

 

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Table of Contents

 

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 September 30, 2013, we had the following natural gas derivative contracts:

 

Contract
Type

 

Period

 

Volume
(MMBtu)

 

Fixed Price or
Sold Ceiling/

Bought Floor

 

Derivative
asset—
current

 

Derivative
liability—
non-current

 

Total Fair
Value of
Contract

 

Swap

 

October 2013 through December 2013

 

552,000

 

$3.60

 

$

2,406

 

$

 

$

2,406

 

Swap

 

October 2013

 

248,000

 

$3.81

 

77,362

 

 

77,362

 

Swap

 

November 2013 through March 2014 (1)

 

1,208,000

 

$3.81

 

60,100

 

 

60,100

 

Swap

 

October 2013 through March 2014

 

1,096,000

 

$3.82

 

162,168

 

 

162,168

 

Collar

 

January 2014 through December 2015

 

3,650,000

 

$4.30/$3.60

 

76,986

 

(210,846

)

(133,860

)

Collar

 

January 2014 through December 2015

 

3,650,000

 

$4.20/$3.50

 

(7,997

)

(360,540

)

(368,537

)

 

 

 

 

10,404,000

 

 

 

$

371,025

 

$

(571,386

)

$

(200,361

)

 


(1)                  On October 2, 2013, the Company terminated the $3.81 swap position for a total of 1,208,000 MMBtus for the period November 2013 through March 2014 for which the Company received $60,100.

 

At December 31, 2012, we had the following natural gas derivative contracts:

 

Contract
Type

 

Period

 

Volume
(MMBtu)

 

Fixed Price or
Sold Ceiling/
Bought Floor

 

Derivative
asset—
current

 

Derivative
liability—
current

 

Derivative
liability—
non-current

 

Total Fair
Value of
Contract

 

Collar

 

January 2014 through December 2015

 

3,650,000

 

$4.30/$3.60

 

$

 

$

 

$

(556,636

)

$

(556,636

)

Collar

 

January 2014 through December 2015

 

3,650,000

 

$4.20/$3.50

 

 

 

(796,266

)

(796,266

)

Swap

 

January 2013 through March 2013

 

360,000

 

$6.42

 

1,100,395

 

 

 

1,100,395

 

Swap

 

January 2013 through March 2013

 

540,000

 

$6.50

 

1,156,734

 

 

 

1,156,734

 

Swap

 

January 2013 through December 2013

 

2,190,000

 

$3.60

 

127,253

 

 

 

127,253

 

Swap

 

January 2013 through March 2014

 

3,640,000

 

$3.81

 

758,669

 

 

(144,994

)

613,675

 

Swap

 

January 2013 through March 2014

 

3,640,000

 

$3.82

 

786,716

 

 

(138,452

)

648,264

 

Swap

 

April 2013 through December 2013

 

2,750,000

 

$3.25

 

 

(919,572

)

 

(919,572

)

 

 

 

 

20,420,000

 

 

 

$

3,929,767

 

$

(919,572

)

$

(1,636,348

)

$

1,373,847

 

 

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Table of Contents

 

At December 31, 2012, we had the following forward sales at NYMEX plus a fixed basis:

 

Period

 

Volume
(MMBtu)

 

Fixed
Basis

 

January 2013 through March 2013

 

450,000

 

$

0.19

 

January 2013 through March 2013

 

918,000

 

$

0.22

 

 

 

1,368,000

 

 

 

 

The aforementioned forward physical sale contracts qualified for normal purchase and sale exemption and, as such, we have elected not to record it on the Consolidated Balance Sheets (Unaudited) using mark-to-market accounting.

 

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 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 (“OTC”) 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 and nine months ended September 30, 2013. 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

 

 

 

September 30, 2013

 

December 31, 2012

 

September 30, 2013

 

December 31, 2012

 

 

 

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)

 

$

371,025

 

Derivative asset (current)

 

$

3,929,767

 

Derivative liability (current)

 

$

 

Derivative liability (current)

 

$

919,572

 

Natural gas hedge positions

 

Derivative asset (non- current)

 

 

Derivative asset (non- current)

 

 

Derivative liability (non- current)

 

571,386

 

Derivative liability (non-current)

 

1,636,348

 

Total derivatives not designated as hedging instruments

 

 

 

$

371,025

 

 

 

$

3,929,767

 

 

 

$

571,386

 

 

 

$

2,555,920

 

 

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Table of Contents

 

The (gains) losses on our hedging instruments included in the unaudited Consolidated Statements of Operations are as follows:

 

The Effect of Derivative Instruments on the Unaudited Consolidated Statements of

Operations for the Three and Nine Months Ended September 30, 2013 and 2012

 

 

 

 

 

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

 

 

 

Location of (Gain)

 

Three Months Ended

 

Nine months Ended

 

 

 

or Loss Recognized in

 

September 30,

 

September 30,

 

Derivatives

 

Income on Derivative

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments under ASC 815-20-25

 

 

 

 

 

 

 

 

 

 

 

Natural gas collar/swap settled positions

 

(Gains) losses on natural gas derivatives

 

$

(361,448

)

$

(3,496,348

)

$

(2,021,116

)

$

(13,600,483

)

Natural gas swap positions terminated (1)

 

(Gains) losses on natural gas derivatives

 

 

 

1,207,050

 

 

Natural gas collar/swap unsettled positions

 

(Gains) losses on natural gas derivatives

 

(263,880

)

8,280,290

 

1,574,208

 

13,258,958

 

 

 

 

 

 

 

 

 

 

 

 

 

Total (gain) loss

 

 

 

$

(625,328

)

$

4,783,942

 

$

760,142

 

$

(341,525

)

 


(1)  The natural gas swap positions were terminated in order to prevent the Company from being over-hedged after the closing of the sale of its coalbed methane properties in Alabama.

 

Note 10—Investment in Canada Energy Partners

 

At September 30, 2013 and December 31, 2012, we own two million shares of Canada Energy Partners (“CEP”), discussed in Note 6—Discontinued Operations, which we classify as available for sale and record at fair value in Other noncurrent assets on the Consolidated Balance Sheets (Unaudited) based on the closing price of the shares on the TSX Venture Exchange on that date. Gains or losses related to both market price fluctuation and currency translation adjustment on the shares of CEP are held in Accumulated other comprehensive loss in the Consolidated Balance Sheets (Unaudited). At September 30, 2013 and December 31, 2012, the value of the shares recorded in Other noncurrent assets was $271,536 and $240,749, respectively, using a Level 1 input. Accumulated other comprehensive loss of $22,233 in the Consolidated Balance Sheets (Unaudited) as of September 30, 2013 consisted of a $25,582 cumulative decrease in market value offset by a $3,349 cumulative gain related to currency translation on the CEP shares. Accumulated other comprehensive loss of $53,020 in the Consolidated Balance Sheets (Unaudited) as of December 31, 2012 consisted of a $61,661 cumulative decrease in market value offset by a $8,641 cumulative gain related to currency translation on the CEP shares.

 

Note 11—Long-Term Debt

 

Under our Credit Agreement, outstanding borrowings may not exceed a borrowing base determined by the lenders.  During 2012, the amounts borrowed under our Credit Agreement exceeded the borrowing base.  Borrowings under the 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 the 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 coal bed 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 the Credit Agreement totaled $77.0 million. The next scheduled borrowing base determination is expected to occur on or around December 15, 2013 and will be based on the Company’s reserves at June 30, 2013.

 

With the closing of the sale of its coalbed methane properties in Alabama, the Company retained a $5.0 million reserve to be disbursed from time to time solely to pay transaction related costs as defined in the Credit Agreement, as amended, until the final settlement date of December 31, 2013, at which time, any remaining reserve shall be used to repay the outstanding principal balance

 

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under the Credit Agreement. At September 30, 2013, a reserve of $1.8 million remained in Cash and cash equivalents in the Consolidated Balance Sheets (Unaudited). Any unused portion of the reserve will be payable to the bank on December 31, 2013.

 

The 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 by the Company. All outstanding borrowings under the Credit Agreement are due and payable on April 1, 2014. The 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 and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.5 million in 2013). As of September 30, 2013, we had $74.0 million of borrowings outstanding under our Credit Agreement. As of September 30, 2013, the interest rates applied to borrowings were 3.24%.

 

For the three months ended September 30, 2013, we had no borrowings and made payments of $3.0 million under the Credit Agreement. For the three months ended September 30, 2012, we borrowed no amounts and made payments of $3.0 million under the Credit Agreement. For the three months ended September 30, 2013 and 2012, interest on the borrowings averaged 3.28% and 3.50% per annum, respectively.

 

For the nine months ended September 30, 2013, we had no borrowings and made payments of $65.3 million under the Credit Agreement. For the nine months ended September 30, 2012, we borrowed $10.5 million and made payments of $22.8 million under the Credit Agreement. For the nine months ended September 30, 2013 and 2012, interest on the borrowings averaged 4.03% and 3.12% per annum, respectively.

 

The following is a summary of our long-term debt at September 30, 2013 and December 31, 2012:

 

 

 

September 30,
2013

 

December 31,
2012

 

 

 

 

 

 

 

Borrowings under Credit Agreement

 

$

74,000,000

 

$

139,300,000

 

Less current maturities included in current liabilities

 

(74,000,000

)

(10,300,000

)

 

 

 

 

 

 

Total long-term debt

 

$

 

$

129,000,000

 

 

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 at September 30, 2013 and December 31, 2012 was estimated to be approximately $72.9 million and $121.6 million, respectively.

 

Note 12—Income Taxes

 

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.

 

For tax reporting purposes, we have federal and state net operating losses (“NOLs”) of approximately $143.4 million and $148.0 million, respectively, at September 30, 2013 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOLs of approximately $137.8 million and $127.0 million, respectively, at December 31, 2012 that were available to reduce future taxable income. Our first material federal NOL carryforward expires in 2022 and the last one expires in 2032.

 

Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 6—Discontinued Operations, of approximately $33.9 million at September 30, 2013 that is available to reduce future taxable capital gains and expiring in 2017.

 

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At September 30, 2013, we have a valuation allowance of $82.4 million recorded against our net deferred tax asset which includes $69.6 million related to our U.S. operations and $12.8 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 6—Discontinued Operations.

 

A reconciliation of the effective tax rate to the statutory rate for the three months ended September 30, 2013 is as follows:

 

 

 

Total

 

 

 

Amount computed using statutory rates

 

$

284,892

 

34.00

%

State income taxes—net of federal benefit

 

7,809

 

0.93

%

Reduction of valuation allowance

 

(722,406

)

-86.21

%

Nondeductible items and other

 

435,955

 

52.03

%

Income tax provision

 

$

6,250

 

0.75

%

 

A reconciliation of the effective tax rate to the statutory rate for the nine months ended September 30, 2013 is as follows:

 

 

 

Total

 

 

 

Amount computed using statutory rates

 

$

12,738,152

 

34.00

%

State income taxes—net of federal benefit

 

883,815

 

2.36

%

Reduction of valuation allowance

 

(14,194,949

)

-37.89

%

Nondeductible items and other

 

591,732

 

1.58

%

Income tax provision

 

$

18,750

 

0.05

%

 

Note 13—Common Stock

 

At September 30, 2013 and December 31, 2012, there were 40,662,749 and 40,690,077 shares, respectively, of common stock outstanding, both including 10,432 shares of treasury stock held by the Company. Also included in common stock outstanding at September 30, 2013 and December 31, 2012 were 158,870 and 254,260 shares of restricted stock, respectively. The following table details the activity related to our common stock for the three months ended September 30, 2013:

 

 

 

Date

 

Shares

 

Common stock outstanding at January 1, 2013

 

 

 

40,690,077

 

Purchased by the Company and cancelled for the payment of withholding taxes due on vested shares of restricted stock

 

01/07/2013

 

(121

)

Purchased by the Company and cancelled for the payment of withholding taxes due on vested shares of restricted stock

 

03/15/2013

 

(470

)

Forfeited upon default of shareholder loans

 

06/06/2013

 

(24,428

)

Shares of restricted stock forfeited upon termination of employment

 

06/14/2013

 

(1,504

)

Shares of restricted stock forfeited upon termination of employment

 

07/08/2013

 

(805

)

Common stock outstanding at September 30, 2013

 

 

 

40,662,749

 

 

Note 14—Series A Convertible Redeemable Preferred Stock

 

At September 30, 2013 and December 31, 2012, 5,818,807 and 5,305,865 shares of preferred stock were issued and outstanding, respectively. At September 30, 2013, an additional 1,583,025 shares of our Series A Convertible Redeemable Preferred Stock (“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 nine months ended September 30, 2013:

 

 

 

Dividend Period
(Three Months Ended)

 

Date Issued

 

Number of Shares

 

Balance

 

 

 

 

 

 

 

 

 

 

 

Balance at January 1, 2013

 

 

 

 

 

5,305,865

 

$

35,851,887

 

Accretion of Preferred Stock

 

 

 

 

 

 

 

1,624,984

 

PIK Dividend Issued for Preferred Stock

 

3/31/13

 

4/1/13

 

165,745

 

1,075,685

 

 

 

6/30/13

 

7/1/13

 

170,931

 

1,367,488

 

 

 

9/30/13

 

9/30/13

 

176,266

 

1,277,889

 

Balance At September 30, 2013

 

 

 

 

 

5,818,807

 

$

41,197,933

 

 

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Note 15—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.

 

During the three months ended September 30, 2013, we recorded a compensation expense accrual of $68,835 which was allocated as an addition of $2,993 to lease operating expenses and an addition of $65,842 to general and administrative expense. During the nine months ended September 30, 2013, we recorded a compensation expense accrual of $188,209 which was allocated as an addition of $16,504 to lease operating expenses and an addition of $171,705 to general and administrative expense. The future compensation cost of all the outstanding awards is $112,268 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 0.56 years.

 

During the three months ended September 30, 2012, we recorded compensation expense of $118,840 of which $7,475 was allocated to lease operating expenses and $111,365 was allocated to general and administrative expenses. During the nine months ended September 30, 2012, we recorded compensation expense of $532,989 of which $29,769 was allocated to lease operating expenses, $351,481was allocated to general and administrative expenses, $131,127 was allocated to restructuring costs, and $20,612 was capitalized to gas properties.

 

Incentive Stock Options

 

The table below summarizes incentive stock option activity for the three months ended September 30, 2013:

 

 

 

Number of
Options

 

Weighted
Average
Exercise
Price

 

Average
Remaining
Contractual
Life

 

Aggregate
Intrinsic
Value

 

Outstanding at December 31, 2012

 

1,412,739

 

$

1.11

 

 

 

 

 

Forfeited

 

(195,584

)

$

1.12

 

 

 

 

 

Outstanding at September 30, 2013

 

1,217,155

 

$

1.11

 

3.0

 

$

 

Options exercisable at September 30, 2013

 

1,062,609

 

$

1.04

 

3.7

 

$

 

 

Non-Qualified Stock Options

 

The table below summarizes non-qualified stock option activity for the three months ended September 30, 2013:

 

 

 

Number of
Options

 

Weighted
Average
Exercise
Price

 

Average
Remaining
Contractual
Life

 

Aggregate
Intrinsic
Value

 

Outstanding at December 31, 2012

 

974,765

 

$

2.33

 

 

 

 

 

Expired

 

(600,000

)

$

2.50

 

 

 

 

 

Outstanding at September 30, 2013

 

374,765

 

$

2.05

 

0.7

 

$

 

Options exercisable at September 30, 2013

 

333,242

 

$

2.22

 

1.8

 

$

 

 

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Restricted Stock Awards

 

The table below summarizes non-vested restricted stock awards activity for the three months ended September 30, 2013:

 

 

 

Number of
Shares

 

Weighted
Average
Grant Date
Fair Value

 

Non-vested restricted stock at December 31, 2012

 

254,260

 

$

1.43

 

Vested

 

(93,416

)

$

0.74

 

Forfeited

 

(1,974

)

$

1.32

 

Non-vested restricted stock at September 30, 2013

 

158,870

 

$

1.83

 

 

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 September 30, 2013.

 

Note 16—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 September 30, 2013, 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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Table of Contents

 

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

 

Statement Regarding Forward-Looking Information

 

Included in this quarterly report are certain forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including statements regarding our reserve quantities and the present value thereof, our ability to continue as a going concern, planned capital expenditures, our ability to continue in compliance with our Credit Agreement, or to refinance our Credit Agreement, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. We use the words “may,” “will,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully and should not place undue reliance on these statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

 

·                  the continued oversupply of natural gas in the US markets, which depresses the price we receive for our natural gas production and makes our properties less valuable and more difficult to sell;

·                  further declines in the prices we receive for our natural gas adversely affecting our operating results, cash flows and credit capacity;

·                  our ability to refinance or repay our indebtedness;

·                  general international and domestic economic conditions that may be less favorable than expected;

·                  changes in our business strategy;

·                  changes in our financial position, including our cash flow and liquidity;

·                  our ability to sell any or all of our assets, if at all, on terms acceptable to us;

·                  the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

·                  volatility in the international and domestic capital and credit markets, including fluctuations in interest rates and availability of capital;

·                  uncertainties in estimating our natural gas reserves;

·                  our ability to replace our natural gas reserves;

·                  uncertainties in exploring for and producing natural gas;

·                  new natural gas development projects and exploration for natural gas in areas where we have little or no proven natural gas reserves;

·                  our ability to acquire water supplies needed for drilling, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental rules;

·                  other persons could have ownership rights in our advanced natural gas extraction techniques which could force us to cease using those techniques or pay royalties;

·                  availability of drilling and production equipment and field service providers;

·                  disruptions, capacity constraints in, or other limitations on the pipeline systems that deliver our natural gas;

·                  our need to use unproven technologies to extract coalbed methane in some properties;

·                  our ability to retain key members of our senior management and key technical employees;

·                  the outcomes of legal proceedings in which we may become involved;

·                  the possibility that the industry may be subject to future regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation);

·                  the effects of government regulation and permitting and other legal requirements;

·                  other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors may negatively impact our businesses, operations or pricing; and

·                  our ability to operate effectively in a state or jurisdiction where land ownership and coalbed methane rights are complicated or unresolved.

 

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Other factors which could affect the events discussed in our forward looking statements are described under “Item 1A. Risk Factors” in our annual report on Form 10-K, which is filed with the SEC, and can be reviewed at www.sec.gov. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this quarterly report. All forward-looking statements speak only as of the date of this quarterly report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

 

Overview

 

GeoMet, Inc. is 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.

 

Natural gas prices in 2012 were depressed compared with prices generally prevailing during prior years and historically low natural gas prices have continued in 2013.  The low natural gas prices in 2012 and 2013 had pervasive adverse consequences to our business, including a borrowing base deficiency under our Credit Agreement. On August 8, 2012, we amended our Credit Agreement to include a conforming tranche equal to the borrowing base, and a non-conforming tranche in the amount of outstanding loans in excess of the borrowing base. The amendment required that we use all of our excess cash flows, as defined, to reduce outstanding borrowings under the Credit Agreement and significantly limited our capital expenditures. On June 14, 2013, we closed the sale of the Alabama properties and used approximately $57.0 million of the proceeds to repay outstanding borrowings under our Credit Agreement. After this repayment, borrowings outstanding under the Credit Agreement totaled $77.0 million. In connection with this repayment the non-conforming portion of borrowings was repaid and the Company no longer has a borrowing base deficiency under the Credit Agreement. The next scheduled borrowing base determination is expected to occur on or around December 15, 2013 and will be based on the Company’s reserves at June 30, 2013. As of September 30, 2013, the interest rates applied to borrowings was 3.24%.  The Credit Agreement continues to have a maturity date of April 1, 2014.

 

Additionally, depressed natural gas prices resulted in significant property impairments and full valuation of our net deferred tax asset during 2012. We believe that low natural gas prices and our indebtedness contributed to our common stock being delisted by NASDAQ as we had no remaining equity and the market price of our common stock had diminished.

 

We previously disclosed our engagement of FBR Capital Markets & Co. to assist the Company in exploring strategic alternatives.  We have concluded that process, and have engaged Lantana Oil & Gas Partners to assist us in pursuing the possible sale of all or substantially all of our assets.

 

No assurance can be given that a suitable proposal for the sale of all or substantially all of our assets will be presented, that any sale transaction will be consummated, or the terms or structure of any transaction if such a sale transaction is consummated.  We currently anticipate that any such transaction would be followed by a liquidation and a distribution of our remaining assets in accordance with applicable law.  This would include the repayment of amounts outstanding under our credit facilities.  The terms of our outstanding Preferred Stock provide that the holders of the Preferred Stock would be entitled to a liquidation preference before the remaining assets, if any, were distributed to the holders of our common stock.

 

It is possible that a prospective purchaser will prefer that a sale be achieved pursuant to a Chapter 11 bankruptcy process.  We also intend to explore the possibility of merging with a viable candidate after completing the sale of all or substantially all of our assets.

 

Any such sale of assets, and subsequent liquidation, would be subject to approval by our board of directors and by holders of a majority of our outstanding shares, with holders of the Preferred Stock voting with the common stock on an as-converted basis.  On an as-converted basis, the Preferred Stock currently represents a majority of the outstanding shares.

 

In connection with the conclusion of our pursuit of strategic alternatives, we are in the process of terminating our engagement of FBR Capital Markets & Co. (“FBR”) and expect to pay FBR $250,000 in settlement of our payment obligations under our engagement agreement with FBR.  In addition, we would expect to pay a contingent payment of $300,000 to FBR for a fairness opinion if requested by us, and a second contingent payment of $300,000 if any assets are sold to certain parties that FBR identified during their engagement and with whom we signed confidentiality agreements prior to the termination of the engagement.

 

During 2011 and the first five months of 2012, prices received for natural gas in the United States continued to decline significantly which we believe, among other things, was due to an over-supply of natural gas, primarily resulting from shale drilling and reduced demand due to a much warmer winter than normal. On April 21, 2012, the Henry Hub spot price closed at $1.825/

 

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MMBtu, its lowest in over ten years. Presented below are the NYMEX Settle Prices for the period January 2011 through November 2013 and the NYMEX Forward Curve Prices (as of November 6, 2013) for natural gas for the period December 2013 through December 2014.

 

 

On June 14, 2013, the Company closed the sale of all of its coal bed methane properties located in Alabama. The sale resulted in proceeds of approximately $62.0 million after purchase price adjustments of $1.2 million to account for net cash flows from the effective date to the closing date. Approximately $57.0 million of the sales proceeds was used to repay outstanding borrowings under the Company’s Credit Agreement and $5.0 million was held in reserve to pay transaction related costs and expenses, including the liquidation of certain natural gas hedge positions.

 

GeoMet’s net interest in the coalbed methane properties in Alabama produced approximately 9,700 Mcf of natural gas per day during the month of March 2013, or approximately 29% of GeoMet’s total production for March 2013. As of March 31, 2013 and based on Securities and Exchange Commission guidelines, GeoMet’s net proved reserves attributable to the coalbed methane properties in Alabama sold were estimated to be approximately 43 Bcf, all classified as proved developed reserves.

 

Areas of Operation

 

Subsequent to the asset sale, our core area of operations is the Central Appalachian Basin of Virginia and West Virginia. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. We also own additional coalbed methane and oil and gas development rights, principally in Virginia and West Virginia. As of September 30, 2013, we own a total of approximately 91,000 net acres of coalbed methane and oil and gas development rights.

 

Central Appalachia

 

Pond Creek and Lasher Fields—We are the operator of 298 producing vertical CBM wells in which we own 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 15.6 MMcf per day and 15.8 MMcf per day for the three and nine months ended September 30, 2013, respectively. Our natural gas production from the Pond Creek field is delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We have 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 is delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtus per day. We also own and operate a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production is gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system.

 

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Table of Contents

 

Pinnate Horizontal Wells—We are the operator of 44 producing pinnate horizontal CBM wells in which we own a 71.6% average working interest in central and northern West Virginia. We also have a 33.7% average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. Net daily sales of natural gas averaged 7.2 MMcf per day and 7.7 MMcf per day for the three and nine months ended September 30, 2013, respectively.  We are party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring from April 2013 through November 2024 which can be automatically extended at GeoMet’s option at the maximum tariff rate. We are also party to a 10,000 MMBtu per day gathering contract that is currently in a month-to-month evergreen term.  In some cases, our natural gas sales volumes are delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes are 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 September 30, 2013.

 

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Table of Contents

 

Natural Gas Production Operations Summary

 

The table below presents information on gas sales, net sales volumes, production expenses and per Mcf data for the three and nine months ended September 30, 2013 and 2012. This table should be read in conjunction with the discussion of the results of operations for the periods presented below (in thousands, except per Mcf amounts).

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Gas sales

 

$

7,392

 

$

9,610

 

$

30,324

 

$

27,465

 

Lease operating expenses

 

$

2,023

 

$

4,417

 

$

10,615

 

$

13,350

 

Compression and transportation expenses

 

1,779

 

2,218

 

5,486

 

6,758

 

Production taxes

 

419

 

442

 

1,617

 

1,276

 

Total production expenses

 

$

4,221

 

$

7,077

 

$

17,718

 

$

21,384

 

 

 

 

 

 

 

 

 

 

 

Net sales volumes (Consolidated) (MMcf)

 

2,072

 

3,391

 

8,088

 

10,468

 

Pond Creek field (Central Appalachian Basin) (MMcf)

 

1,386

 

1,462

 

4,209

 

4,402

 

Other Central Appalachian Basin fields (MMcf)

 

686

 

912

 

2,224

 

2,941

 

Gurnee field (Cahaba Basin) (MMcf)

 

 

430

 

723

 

1,325

 

Black Warrior Basin fields (MMcf)

 

 

587

 

932

 

1,800

 

 

 

 

 

 

 

 

 

 

 

Per Mcf data ($/Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

3.74

 

$

3.87

 

$

3.85

 

$

3.92

 

 

 

 

 

 

 

 

 

 

 

Average natural gas sales price (Consolidated)

 

$

3.57

 

$

2.83

 

$

3.75

 

$

2.62

 

Pond Creek field (Central Appalachian Basin)

 

$

3.60

 

$

2.88

 

$

3.78

 

$

2.70

 

Other Central Appalachian Basin fields

 

$

3.50

 

$

2.69

 

$

3.69

 

$

2.48

 

Gurnee field (Cahaba Basin) (2)

 

$

 

$

2.87

 

$

3.77

 

$

2.63

 

Black Warrior Basin fields (2)

 

$

 

$

2.92

 

$

3.73

 

$

2.68

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (Consolidated)

 

$

0.98

 

$

1.30

 

$

1.31

 

$

1.28

 

Pond Creek field (Central Appalachian Basin)

 

$

1.07

 

$

1.13

 

$

1.12

 

$

1.07

 

Other Central Appalachian Basin fields

 

$

0.78

 

$

1.34

 

$

1.41

 

$

1.40

 

Gurnee field (Cahaba Basin) (2)

 

$

 

$

2.79

 

$

2.84

 

$

2.67

 

Black Warrior Basin fields (2)

 

$

 

$

0.56

 

$

0.74

 

$

0.53

 

Compression and transportation expenses (Consolidated)

 

$

0.86

 

$

0.66

 

$

0.68

 

$

0.64

 

Pond Creek field (Central Appalachian Basin)

 

$

0.75

 

$

0.61

 

$

0.66

 

$

0.59

 

Other Central Appalachian Basin fields

 

$

1.07

 

$

1.18

 

$

1.03

 

$

1.17

 

Gurnee field (Cahaba Basin) (2)

 

$

 

$

0.29

 

$

0.29

 

$

0.27

 

Black Warrior Basin fields (2)

 

$

 

$

0.22

 

$

0.18

 

$

0.20

 

Production taxes (Consolidated)

 

$

0.20

 

$

0.13

 

$

0.20

 

$

0.12

 

Pond Creek field (Central Appalachian Basin)

 

$

0.20

 

$

0.15

 

$

0.21

 

$

0.15

 

Other Central Appalachian Basin fields

 

$

0.21

 

$

0.07

 

$

0.19

 

$

0.07

 

Gurnee field (Cahaba Basin) (2)

 

$

 

$

0.13

 

$

0.18

 

$

0.11

 

Black Warrior Basin fields (2)

 

$

 

$

0.17

 

$

0.23

 

$

0.16

 

Total production expenses (Consolidated)

 

$

2.04

 

$

2.09

 

$

2.19

 

$

2.04

 

Pond Creek field (Central Appalachian Basin)

 

$

2.02

 

$

1.89

 

$

1.99

 

$

1.81

 

Other Central Appalachian Basin fields

 

$

2.06

 

$

2.59

 

$

2.63

 

$

2.64

 

Gurnee field (Cahaba Basin) (2)

 

$

 

$

3.21

 

$

3.31

 

$

3.05

 

Black Warrior Basin fields (2)

 

$

 

$

0.95

 

$

1.13

 

$

0.89

 

Depletion (Consolidated)

 

$

0.40

 

$

0.72

 

$

0.45

 

$

0.87

 

 


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

(3)                  On June 14, 2013, the Company closed the sale of all of its coal bed methane properties located in the state of Alabama.

 

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Table of Contents

 

Results of Operations

 

Three months ended September 30, 2013 compared with three months ended September 30, 2012

 

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 September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

 

 

(In thousands)

 

 

 

Gas sales

 

$

7,392

 

$

9,610

 

-23

%

Lease operating expenses

 

$

2,023

 

$

4,417

 

-54

%

Compression expense

 

$

1,098

 

$

1,167

 

-6

%

Transportation expense

 

$

681

 

$

1,050

 

-35

%

Production taxes

 

$

419

 

$

442

 

-5

%

Depreciation, depletion and amortization

 

$

870

 

$

2,540

 

-66

%

Impairment of gas properties

 

$

 

$

25,432

 

NM

 

General and administrative

 

$

1,049

 

$

1,097

 

-4

%

Restructuring costs