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 June 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 August 1, 2013, 40,662,749 shares and 5,642,541 shares, respectively, of the registrants common stock and preferred stock, par value $0.001 per share, were outstanding.
GEOMET, INC. AND SUBSIDIARIES
Consolidated Balance Sheets (Unaudited)
|
|
June 30, 2013 |
|
December 31, 2012 |
| ||
ASSETS |
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash and cash equivalents |
|
$ |
11,533,406 |
|
$ |
7,234,225 |
|
Accounts receivable, net of allowance of $14,744 and $17,634 at June 30, 2013 and December 31, 2012, respectively |
|
4,817,473 |
|
6,248,819 |
| ||
Inventory |
|
106,974 |
|
262,885 |
| ||
Derivative assetnatural gas contracts |
|
360,679 |
|
3,929,767 |
| ||
Other current assets |
|
847,772 |
|
1,437,819 |
| ||
Total current assets |
|
17,666,304 |
|
19,113,515 |
| ||
Gas propertiesutilizing the full cost method of accounting: |
|
|
|
|
| ||
Proved gas properties |
|
333,524,433 |
|
539,077,119 |
| ||
Other property and equipment |
|
3,332,394 |
|
3,749,621 |
| ||
Total property and equipment |
|
336,856,827 |
|
542,826,740 |
| ||
Less accumulated depreciation, depletion, amortization and impairment of gas properties |
|
(292,324,195 |
) |
(467,702,053 |
) | ||
Property and equipmentnet |
|
44,532,632 |
|
75,124,687 |
| ||
Other noncurrent assets: |
|
|
|
|
| ||
Deferred income taxes |
|
99,365 |
|
1,125,804 |
| ||
Other |
|
840,799 |
|
962,451 |
| ||
Total other noncurrent assets |
|
940,164 |
|
2,088,255 |
| ||
TOTAL ASSETS |
|
$ |
63,139,100 |
|
$ |
96,326,457 |
|
LIABILITIES, MEZZANINE AND STOCKHOLDERS DEFICIT |
|
|
|
|
| ||
Current Liabilities: |
|
|
|
|
| ||
Accounts payable |
|
$ |
3,972,380 |
|
$ |
5,728,879 |
|
Royalties payable |
|
3,621,726 |
|
3,830,904 |
| ||
Accrued liabilities |
|
2,870,771 |
|
1,793,946 |
| ||
Paid in-kind dividend payable on Series A Convertible Redeemable Preferred Stock |
|
1,367,488 |
|
|
| ||
Deferred income taxes |
|
99,365 |
|
1,125,804 |
| ||
Derivative liabilitynatural gas contracts |
|
|
|
919,572 |
| ||
Asset retirement obligations |
|
11,983 |
|
73,706 |
| ||
Current portion of long-term debt |
|
77,000,000 |
|
10,300,000 |
| ||
Total current liabilities |
|
88,943,713 |
|
23,772,811 |
| ||
Long-term debt |
|
|
|
129,000,000 |
| ||
Asset retirement obligations |
|
9,387,734 |
|
13,235,318 |
| ||
Derivative liabilitynatural gas contracts |
|
824,920 |
|
1,636,348 |
| ||
Other long-term accrued liabilities |
|
128,558 |
|
143,682 |
| ||
TOTAL LIABILITIES |
|
99,284,925 |
|
167,788,159 |
| ||
Commitments and contingencies (Note 16) |
|
|
|
|
| ||
Mezzanine equity: |
|
|
|
|
| ||
Series A Convertible Redeemable Preferred Stocknet of offering costs of $1,660,435; redemption amount $53,058,650; $.001 par value; 7,401,832 shares authorized, 5,471,610 and 5,305,865 shares were issued and outstanding at June 30, 2013 and December 31, 2012, respectively |
|
37,953,945 |
|
35,851,887 |
| ||
Stockholders Deficit: |
|
|
|
|
| ||
Preferred stock, $0.001 par value2,598,168 shares authorized, none issued |
|
|
|
|
| ||
Common stock, $0.001 par valueauthorized 125,000,000 shares; 40,663,554 and 40,690,077 issued and outstanding at June 30, 2013 and December 31, 2012, respectively |
|
40,664 |
|
40,690 |
| ||
Treasury stock10,432 shares at June 30, 2013 and December 31, 2012 |
|
(94,424 |
) |
(94,424 |
) | ||
Paid-in capital |
|
191,499,298 |
|
195,033,585 |
| ||
Accumulated other comprehensive loss |
|
(102,547 |
) |
(53,020 |
) | ||
Retained deficit |
|
(265,442,761 |
) |
(302,057,496 |
) | ||
Less notes receivable |
|
|
|
(182,924 |
) | ||
Total stockholders deficit |
|
(74,099,770 |
) |
(107,313,589 |
) | ||
TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS DEFICIT |
|
$ |
63,139,100 |
|
$ |
96,326,457 |
|
See accompanying Notes to Consolidated Financial Statements (Unaudited)
GEOMET, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
| ||||||||
|
|
2013 |
|
2012 |
|
2013 |
|
2012 |
| ||||
Revenues: |
|
|
|
|
|
|
|
|
| ||||
Gas sales |
|
$ |
12,053,170 |
|
$ |
7,711,969 |
|
$ |
22,932,434 |
|
$ |
17,855,143 |
|
Operating fees |
|
38,113 |
|
59,446 |
|
83,069 |
|
135,211 |
| ||||
Total revenues |
|
12,091,283 |
|
7,771,415 |
|
23,015,503 |
|
17,990,354 |
| ||||
Operating expenses: |
|
|
|
|
|
|
|
|
| ||||
Lease operating expense |
|
4,122,868 |
|
4,491,593 |
|
8,592,107 |
|
8,933,027 |
| ||||
Compression and transportation expense |
|
1,868,165 |
|
2,300,765 |
|
3,706,801 |
|
4,540,254 |
| ||||
Production taxes |
|
647,371 |
|
364,437 |
|
1,197,917 |
|
834,086 |
| ||||
Depreciation, depletion and amortization |
|
1,370,777 |
|
3,290,420 |
|
2,877,143 |
|
6,920,889 |
| ||||
Impairment of gas properties |
|
|
|
42,255,847 |
|
|
|
58,035,288 |
| ||||
General and administrative |
|
1,408,521 |
|
1,366,142 |
|
2,406,754 |
|
2,668,167 |
| ||||
Restructuring costs |
|
17,396 |
|
765,233 |
|
87,584 |
|
765,233 |
| ||||
(Gains) losses on natural gas derivatives |
|
(4,149,649 |
) |
4,891,613 |
|
1,385,470 |
|
(5,125,467 |
) | ||||
Total operating expenses |
|
5,285,449 |
|
59,726,050 |
|
20,253,776 |
|
77,571,477 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Gain on the sale of Properties in Alabama |
|
37,135,611 |
|
|
|
37,135,611 |
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Operating income (loss) |
|
43,941,445 |
|
(51,954,635 |
) |
39,897,338 |
|
(59,581,123 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Other income (expense): |
|
|
|
|
|
|
|
|
| ||||
Interest income |
|
428 |
|
597 |
|
848 |
|
4,299 |
| ||||
Interest expense |
|
(1,559,276 |
) |
(1,268,399 |
) |
(3,235,605 |
) |
(2,544,243 |
) | ||||
Other |
|
(6,698 |
) |
253 |
|
(35,346 |
) |
(4,099 |
) | ||||
Total other income (expense): |
|
(1,565,546 |
) |
(1,267,549 |
) |
(3,270,103 |
) |
(2,544,043 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Income (loss) before income taxes from continuing operations |
|
42,375,899 |
|
(53,222,184 |
) |
36,627,235 |
|
(62,125,166 |
) | ||||
Income tax expense |
|
(6,250 |
) |
(6,250 |
) |
(12,500 |
) |
(44,030,700 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Income (loss) from continuing operations |
|
42,369,649 |
|
(53,228,434 |
) |
36,614,735 |
|
(106,155,866 |
) | ||||
Discontinued operations, net of tax |
|
|
|
(675,809 |
) |
|
|
(696,381 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
|
$ |
42,369,649 |
|
$ |
(53,904,243 |
) |
$ |
36,614,735 |
|
$ |
(106,852,247 |
) |
Accretion of Series A Convertible Redeemable Preferred Stock |
|
(532,836 |
) |
(470,953 |
) |
(1,026,373 |
) |
(932,969 |
) | ||||
Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock |
|
(1,367,488 |
) |
(619,625 |
) |
(2,443,173 |
) |
(1,860,345 |
) | ||||
Cash dividends paid on Series A Convertible Redeemable Preferred Stock |
|
(568 |
) |
(651 |
) |
(1,201 |
) |
(1,296 |
) | ||||
Net income (loss) available to common stockholders |
|
$ |
40,468,757 |
|
$ |
(54,995,472 |
) |
$ |
33,143,988 |
|
$ |
(109,646,857 |
) |
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common sharebasic: |
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common share from continuing operations |
|
$ |
1.00 |
|
$ |
(1.36 |
) |
$ |
0.82 |
|
$ |
(2.74 |
) |
Net loss per common share from discontinued operations |
|
|
|
(0.01 |
) |
|
|
(0.01 |
) | ||||
Net income (loss) per common sharebasic |
|
$ |
1.00 |
|
$ |
(1.37 |
) |
$ |
0.82 |
|
$ |
(2.75 |
) |
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common sharediluted: |
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common share from continuing operations |
|
$ |
0.51 |
|
$ |
(1.36 |
) |
$ |
0.45 |
|
$ |
(2.74 |
) |
Net loss per common share from discontinued operations |
|
|
|
(0.01 |
) |
|
|
(0.01 |
) | ||||
Net income (loss) per common sharediluted |
|
$ |
0.51 |
|
$ |
(1.37 |
) |
$ |
0.45 |
|
$ |
(2.75 |
) |
|
|
|
|
|
|
|
|
|
| ||||
Weighted average number of common shares: |
|
|
|
|
|
|
|
|
| ||||
Basic |
|
40,477,411 |
|
40,003,977 |
|
40,467,149 |
|
39,883,409 |
| ||||
Diluted |
|
82,683,271 |
|
40,003,977 |
|
82,039,050 |
|
39,883,409 |
|
See accompanying Notes to Consolidated Financial Statements (Unaudited)
GEOMET, INC. AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
(Unaudited)
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
| ||||||||
|
|
2013 |
|
2012 |
|
2013 |
|
2012 |
| ||||
Net income (loss) |
|
$ |
42,369,649 |
|
$ |
(53,904,243 |
) |
$ |
36,614,735 |
|
$ |
(106,852,247 |
) |
(Loss) gain on foreign currency translation adjustment |
|
(10,350 |
) |
9,470 |
|
(9,118 |
) |
2,019 |
| ||||
Unrealized (loss) gain on available for sale securities |
|
(60,472 |
) |
36,952 |
|
(40,409 |
) |
36,952 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Other comprehensive income (loss) |
|
$ |
42,298,827 |
|
$ |
(53,857,821 |
) |
$ |
36,565,208 |
|
$ |
(106,813,276 |
) |
See accompanying Notes to Consolidated Financial Statements (Unaudited)
GEOMET, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
|
|
Six Months Ended June 30, |
| ||||
|
|
2013 |
|
2012 |
| ||
Cash flows provided by operating activities: |
|
|
|
|
| ||
Net income (loss) |
|
$ |
36,614,735 |
|
$ |
(106,852,247 |
) |
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: |
|
|
|
|
| ||
Depreciation, depletion and amortization |
|
2,877,143 |
|
6,919,168 |
| ||
Impairment of gas properties |
|
|
|
58,035,288 |
| ||
Amortization of debt issuance costs |
|
454,340 |
|
316,671 |
| ||
Deferred income tax expense |
|
|
|
44,018,200 |
| ||
Unrealized losses from the change in market value of open derivative contracts |
|
1,838,088 |
|
4,978,668 |
| ||
Stock-based compensation |
|
119,374 |
|
393,536 |
| ||
Gain on the sale of Properties in Alabama |
|
(37,135,611 |
) |
|
| ||
Loss on sale of Hudsons Hope Gas, Ltd |
|
|
|
683,154 |
| ||
Loss on sale of other assets |
|
35,348 |
|
5,200 |
| ||
Accretion expenseasset retirement obligation |
|
612,553 |
|
391,687 |
| ||
Changes in operating assets and liabilities: |
|
|
|
|
| ||
Accounts receivable |
|
2,100,139 |
|
810,421 |
| ||
Other assets |
|
99,190 |
|
477,654 |
| ||
Accounts payable |
|
(2,408,500 |
) |
(675,844 |
) | ||
Other accrued liabilities |
|
1,139,382 |
|
912,190 |
| ||
|
|
|
|
|
| ||
Net cash provided by operating activities |
|
6,346,181 |
|
10,413,746 |
| ||
|
|
|
|
|
| ||
Cash flows provided by investing activities: |
|
|
|
|
| ||
Capital expenditures |
|
(494,031 |
) |
(508,657 |
) | ||
Return of original basis through the settlement of natural gas derivative contracts |
|
|
|
4,925,738 |
| ||
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 |
|
60,258,020 |
|
4,420,581 |
| ||
|
|
|
|
|
| ||
Cash flows used in financing activities: |
|
|
|
|
| ||
Proceeds from revolving credit facility borrowings |
|
|
|
10,500,000 |
| ||
Payments on revolving credit facility |
|
(62,300,000 |
) |
(19,800,000 |
) | ||
Deferred financing costs |
|
(3,801 |
) |
(403,383 |
) | ||
Payments on other debt |
|
|
|
(167,087 |
) | ||
Purchase and cancellation of treasury stock |
|
(586 |
) |
(2,037 |
) | ||
Cash dividends paid on Series A Convertible Redeemable Preferred Stock |
|
(633 |
) |
(1,296 |
) | ||
|
|
|
|
|
| ||
Net cash used in financing activities |
|
(62,305,020 |
) |
(9,873,803 |
) | ||
Effect of exchange rate changes on cash |
|
|
|
5,115 |
| ||
|
|
|
|
|
| ||
Increase in cash and cash equivalents |
|
4,299,181 |
|
4,965,639 |
| ||
Cash and cash equivalents at beginning of period |
|
7,234,225 |
|
457,865 |
| ||
|
|
|
|
|
| ||
Cash and cash equivalents at end of period |
|
$ |
11,533,406 |
|
$ |
5,423,504 |
|
|
|
|
|
|
| ||
Supplemental disclosure of cash flow information: |
|
|
|
|
| ||
Cash paid during the period for interest expense |
|
$ |
1,664,956 |
|
$ |
2,509,404 |
|
|
|
|
|
|
| ||
Cash paid during the period for income taxes |
|
$ |
12,500 |
|
$ |
12,500 |
|
|
|
|
|
|
| ||
Significant noncash investing and financing activities: |
|
|
|
|
| ||
Accrued capital expenditures |
|
$ |
444,102 |
|
$ |
817,015 |
|
See accompanying Notes to Consolidated Financial Statements (Unaudited)
GEOMET, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)
Note 1Organization 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, 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.
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 normal and customary 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 Companys 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 and such amount has been established as the new borrowing base. In connection with this repayment the non-conforming Tranche B portion of total outstanding borrowings, which has existed since August 2012, has been eliminated 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 Companys reserves at June 30, 2013. The Credit Agreement continues to have a maturity date of April 1, 2014.
GeoMets net interest in the sold properties 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 GeoMets total production for this time period. As of April 1, 2013 and based on Securities and Exchange Commission guidelines, GeoMets 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 |
|
Buyers assumption of asset retirement obligations |
|
4,411,201 |
| |
Buyers 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 |
|
(1,206,128 |
) | |
Total gain on sale |
|
$ |
37,135,611 |
|
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, under GAAP, our pre-gain net deferred tax asset of $97.4 million and the offsetting $97.4 valuation allowance recorded against it were both reduced by $14.2 million as a result of recording the gain. At June 30, 2013, the remaining net deferred tax asset is $83.2 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 registrant, and (iii) factually supportable. As such, included in Net income (loss), Net income (loss) available to common stockholders and Net income (loss) per common share (basic and diluted) is the Total gain on sale disclosed above of $37,135,611.
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
| ||||||||
|
|
2013 |
|
2012 |
|
2013 |
|
2012 |
| ||||
Revenue |
|
$ |
8,969,890 |
|
$ |
5,452,801 |
|
$ |
16,770,976 |
|
$ |
12,535,769 |
|
Income (loss) from continuing operations |
|
$ |
41,421,377 |
|
$ |
(39,469,009 |
) |
$ |
34,960,777 |
|
$ |
(86,907,781 |
) |
Net income (loss) |
|
$ |
41,421,377 |
|
$ |
(40,144,818 |
) |
$ |
34,960,777 |
|
$ |
(87,604,162 |
) |
Net income (loss) available to common stockholders |
|
$ |
39,520,485 |
|
$ |
(41,236,047 |
) |
$ |
31,490,030 |
|
$ |
(90,398,772 |
) |
Net income (loss) per common sharebasic |
|
$ |
0.98 |
|
$ |
(1.03 |
) |
$ |
0.78 |
|
$ |
(2.27 |
) |
Net income (loss) per common sharediluted |
|
$ |
0.50 |
|
$ |
(1.03 |
) |
$ |
0.43 |
|
$ |
(2.27 |
) |
Note 3 Going Concern and Managements Plans
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 2012, the amounts outstanding under the Companys Fifth Amended and Restated Credit Agreement (Credit Agreement) exceeded the borrowing base as determined by the lenders under the Credit Agreement. Although the recent sale of gas properties by the Company caused the Company to be in conformity with its borrowing base, the Company remains highly leveraged. In addition, the Credit Agreement matures on April 1, 2014, and no assurances can be made that the Company will be able to refinance, repay or further extend the maturity date of the Credit Agreement. Also, as of June 30, 2013, the Company had a working capital deficit of $71.3 million, a retained deficit of $265.4 million and stockholders deficit of $74.1 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 the Companys Credit Agreement was reclassified to current liabilities. These and other factors raise substantial doubt about the Companys ability to continue as a going concern for the next twelve months.
Managements current business plan is to continue to evaluate its strategic alternatives. Additionally, management is seeking to divest properties with limited value and will consider additional asset sale opportunities as they arise. Management also remains focused on maintaining compliance with the Credit Agreement, as amended, maintaining production levels, and keeping costs under control.
The ability of the Company to continue as a going concern is dependent upon its ability to generate sufficient cash flows and sales proceeds or other sources of capital sufficient to repay or refinance its indebtedness, continue its operations and fund its long-term capital needs. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.
Note 4Recent 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 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 9Derivative Instruments and Hedging Activities.
Note 5Net Income (Loss) Per Common Share
Net income (loss) per common sharebasic is calculated by dividing Net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common sharediluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income (loss) available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net income (loss) per common sharediluted 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 income (loss) per common share is as follows:
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
| ||||||||
|
|
2013 |
|
2012 |
|
2013 |
|
2012 |
| ||||
Net income (loss) available to common stockholdersbasic |
|
$ |
40,468,757 |
|
$ |
(54,995,472 |
) |
$ |
33,143,988 |
|
$ |
(109,646,857 |
) |
Dilutive related add back: |
|
|
|
|
|
|
|
|
| ||||
Accretion of Preferred Stock |
|
532,836 |
|
470,953 |
|
1,026,373 |
|
932,969 |
| ||||
Paid-in-kind dividends on Preferred Stock |
|
1,367,488 |
|
619,625 |
|
2,443,173 |
|
1,860,345 |
| ||||
Cash dividends paid on Preferred Stock |
|
568 |
|
651 |
|
1,201 |
|
1,296 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) available to common stockholdersdiluted |
|
$ |
42,369,649 |
|
$ |
(53,904,243 |
) |
$ |
36,614,735 |
|
$ |
(106,852,247 |
) |
Net income (loss) per common sharebasic: |
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common share from continuing operations |
|
$ |
1.00 |
|
$ |
(1.36 |
) |
$ |
0.82 |
|
$ |
(2.74 |
) |
Net loss per common share from discontinued operations |
|
|
|
(0.01 |
) |
|
|
(0.01 |
) | ||||
Net income (loss) per common sharebasic |
|
$ |
1.00 |
|
$ |
(1.37 |
) |
$ |
0.82 |
|
$ |
(2.75 |
) |
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common sharediluted: |
|
|
|
|
|
|
|
|
| ||||
Net income (loss) per common share from continuing operations |
|
$ |
0.51 |
|
$ |
(1.36 |
) |
$ |
0.45 |
|
$ |
(2.74 |
) |
Net loss per common share from discontinued operations |
|
|
|
(0.01 |
) |
|
|
(0.01 |
) | ||||
Net income (loss) per common sharediluted |
|
$ |
0.51 |
|
$ |
(1.37 |
) |
$ |
0.45 |
|
$ |
(2.75 |
) |
Weighted average number of common shares: |
|
|
|
|
|
|
|
|
| ||||
Basic |
|
40,477,411 |
|
40,003,977 |
|
40,467,149 |
|
39,883,409 |
| ||||
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
| ||||
Preferred stock |
|
42,089,307 |
|
|
|
41,455,348 |
|
|
| ||||
Restricted stock units |
|
116,553 |
|
|
|
116,553 |
|
|
| ||||
Diluted |
|
82,683,271 |
|
40,003,977 |
|
82,039,050 |
|
39,883,409 |
|
Net income (loss) per common sharebasic for both the three and six months ended June 30, 2013 included $0.92 per common share, net of $0 tax, resulting from the Gain on the sale of Properties in Alabama. Net income (loss) per common sharediluted for both the three and six months ended June 30, 2013 included $0.45 per common share, net of $0 tax, resulting from the Gain on the sale of Properties in Alabama.
Net income per common sharediluted for the three months ended June 30, 2013 excluded the effect of outstanding exercisable options to purchase 2,099,658 shares and 231,457 weighted average restricted shares outstanding because they were assumed reacquired under the treasury stock method.
Net income per common sharediluted for the six months ended June 30, 2013 excluded the effect of outstanding exercisable options to purchase 2,099,658 shares and 232,274 weighted average restricted shares outstanding because they were assumed reacquired under the treasury stock method.
Net loss per common sharediluted for the three months ended June 30, 2012 excluded the effect of outstanding exercisable options to purchase 2,490,558 shares, 164,565 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 268,739 weighted average restricted shares outstanding, and 4,691,632 shares of Series A Convertible Redeemable Preferred Stock (36,089,476 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.
Net loss per common sharediluted for the six months ended June 30, 2012 excluded the effect of outstanding exercisable options to purchase 2,490,558 shares, 198,327 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 258,399 weighted average restricted shares outstanding, and 4,549,537 shares of Series A Convertible Redeemable Preferred Stock (34,996,440 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.
Note 6Discontinued Operations
On June 20, 2012, we disposed of Hudsons 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 we are restricted from selling 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 six months ended June 30, 2013 and 2012 were as follows:
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
| ||||||||
|
|
2013 |
|
2012 |
|
2013 |
|
2012 |
| ||||
Revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
Total operating benefit (expenses) |
|
|
|
7,426 |
|
|
|
(13,123 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Operating income (loss) |
|
|
|
7,426 |
|
|
|
(13,123 |
) | ||||
Loss on sale of Hudsons Hope, Ltd. |
|
|
|
(683,154 |
) |
|
|
(683,154 |
) | ||||
Other income (expense) |
|
|
|
(81 |
) |
|
|
(104 |
) | ||||
Income tax expense |
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net loss |
|
$ |
|
|
$ |
(675,809 |
) |
$ |
|
|
$ |
(696,381 |
) |
Note 7Gas 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
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 June 30, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.47 per Mcf, resulting in a natural gas price of $3.53 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 June 30, 2013.
For the twelve months ended June 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.17 per Mcf, resulting in a natural gas price of $3.34 per Mcf when adjusted for regional price differentials. For the three and six months ended June 30, 2012, we recorded a $42.3 million and a $58.0 million write-downs, 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 six months ended June 30, 2013.
Note 8Asset 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 six months ended June 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 |
| |
Buyers assumption of asset retirement obligations |
|
(4,411,201 |
) | |
Settlements |
|
(110,659 |
) | |
Accretion |
|
612,553 |
| |
Asset retirement liability at June 30, 2013 |
|
9,399,717 |
| |
Less: Current portion of liability |
|
(11,983 |
) | |
Long-term asset retirement liability |
|
$ |
9,387,734 |
|
Note 9Derivative 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 June 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.
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 June 30, 2013, we had the following natural gas derivative contracts:
Contract |
|
Period |
|
Volume |
|
Fixed Price or |
|
Derivative |
|
Derivative |
|
Total Fair |
| |||
Collar |
|
January 2014 through December 2015 |
|
3,650,000 |
|
$4.30/$3.60 |
|
$ |
25,275 |
|
$ |
(327,599 |
) |
$ |
(302,324 |
) |
Collar |
|
January 2014 through December 2015 |
|
3,650,000 |
|
$4.20/$3.50 |
|
(32,176 |
) |
(497,321 |
) |
(529,497 |
) | |||
Swap |
|
July 2013 through December 2013 |
|
1,104,000 |
|
$3.60 |
|
(47,156 |
) |
|
|
(47,156 |
) | |||
Swap |
|
July 2013 through March 2014 |
|
2,192,000 |
|
$3.81 |
|
184,627 |
|
|
|
184,627 |
| |||
Swap |
|
July 2013 through March 2014 |
|
1,832,000 |
|
$3.82 |
|
230,109 |
|
|
|
230,109 |
| |||
|
|
|
|
12,428,000 |
|
|
|
$ |
360,679 |
|
$ |
(824,920 |
) |
$ |
(464,241 |
) |
At December 31, 2012, we had the following natural gas derivative contracts:
Contract |
|
Period |
|
Volume |
|
Fixed Price or |
|
Derivative |
|
Derivative |
|
Derivative |
|
Total Fair |
| ||||
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 |
|
At December 31, 2012, we had the following forward sales at NYMEX plus a fixed basis:
Period |
|
Volume |
|
Fixed |
| |
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 and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. 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 counterparties and our credit risk, we have considered the effect of credit risk on the fair value of the assets and liabilities related to the items stated below. 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 13-week 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 stated interest rates of the debt instruments included our long-term debt.
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.
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 six months ended June 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 |
| ||||||||||||||||
|
|
June 30, 2013 |
|
December 31, 2012 |
|
June 30, 2013 |
|
December 31, 2012 |
| ||||||||||||
|
|
Balance Sheet |
|
Fair |
|
Balance Sheet |
|
Fair |
|
Balance Sheet |
|
Fair |
|
Balance Sheet |
|
Fair |
| ||||
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Natural gas hedge positions |
|
Derivative asset (current) |
|
$ |
360,679 |
|
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) |
|
824,920 |
|
Derivative liability (non-current) |
|
1,636,348 |
| ||||
Total derivatives not designated as hedging instruments |
|
|
|
$ |
360,679 |
|
|
|
$ |
3,929,767 |
|
|
|
$ |
824,920 |
|
|
|
$ |
2,555,920 |
|
The following (gains) losses on our hedging instruments included in the unaudited Consolidated Statements of Operations and Other Comprehensive Income (Loss) (OCI) are as follows:
The Effect of Derivative Instruments on the Unaudited Consolidated Statements of Operations and
Other Comprehensive Income for the Three and six months ended June 30, 2013 and 2012
|
|
|
|
Amount of (Gain) or Loss |
| ||||||||||
|
|
Location of (Gain) |
|
Three Months Ended |
|
Six Months Ended |
| ||||||||
|
|
or Loss Recognized in |
|
June 30, |
|
June 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 |
|
$ |
1,440,084 |
|
$ |
(5,311,266 |
) |
$ |
(1,659,668 |
) |
$ |
(10,104,135 |
) |
Natural gas swap positions terminated (1) |
|
(Gains) losses on natural gas derivatives |
|
1,207,050 |
|
|
|
1,207,050 |
|
|
| ||||
Natural gas collar/swap unsettled positions |
|
(Gains) losses on natural gas derivatives |
|
(6,796,783 |
) |
10,202,879 |
|
1,838,088 |
|
4,978,668 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total (gain) loss |
|
|
|
$ |
(4,149,649 |
) |
$ |
4,891,613 |
|
$ |
1,385,470 |
|
$ |
(5,125,467 |
) |
(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 10Investment in Canada Energy Partners
At June 30, 2013 and December 31, 2012, we own two million shares of Canada Energy Partners (CEP), discussed in Note 6Discontinued 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 June 30, 2013 and December 31, 2012, the value of the shares recorded in Other noncurrent assets was $191,222 and $240,749, respectively, using a Level 1 input. Accumulated other comprehensive loss of $102,547 in the Consolidated Balance Sheets (Unaudited) as of June 30, 2013 consisted of a $102,070 cumulative decrease in market value and a $477 cumulative loss 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 11Long-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. On August 8, 2012, in connection with the excess of borrowings over the borrowing base, we amended the Credit Agreement. Borrowings under the Credit Agreement at August 8, 2012 totaled $148.6 million. The Credit Agreement, as amended, provided 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 Companys Credit Agreement, which eliminated the borrowing base deficiency. After this repayment, borrowings outstanding under the Credit Agreement totaled $77.0 million. The new borrowing base will be the lesser of the total amount of outstanding borrowings under the Credit Agreement and the current balance of $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 Companys 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 of the Tranche A Loans until repaid in full. At June 30, 2013, a reserve of $2.1 million remained in Cash and cash equivalents in the Consolidated Balance Sheets (Unaudited).
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 agents 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 June 30, 2013, we had $77.0 million of borrowings outstanding under our Credit Agreement. As of June 30, 2013, the interest rates applied to borrowings were 3.24%.
For the three months ended June 30, 2013, we had no borrowings and made payments of $57.8 million under the Credit Agreement. For the three months ended June 30, 2012 we borrowed $3.1 million and made payments of $4.0 million under the Credit Agreement. For the three months ended June 30, 2013 and 2012, interest on the borrowings averaged 3.83% and 2.99% per annum, respectively.
For the six months ended June 30, 2013, we had no borrowings and made payments of $62.3 million under the Credit Agreement. For the six months ended June 30, 2012 we borrowed $10.5 million and made payments of $19.8 million under the Credit Agreement. For the six months ended June 30, 2013 and 2012, interest on the borrowings averaged 4.06% and 2.94% per annum, respectively.
The following is a summary of our long-term debt at June 30, 2013 and December 31, 2012:
|
|
June 30, |
|
December 31, |
| ||
|
|
|
|
|
| ||
Borrowings under Credit Agreement |
|
$ |
77,000,000 |
|
$ |
139,300,000 |
|
Less current maturities included in current liabilities |
|
(77,000,000 |
) |
(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 June 30, 2013 and December 31, 2012 was estimated to be approximately $73.7 million and $121.6 million, respectively.
Note 12Income 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 $138.1 million and $143.4 million, respectively, at June 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 Hudsons Hope Gas, Ltd., as described in Note 6Discontinued Operations, of approximately $34.9 million at June 30, 2013 that is available to reduce future taxable capital gains and expiring in 2017.
At June 30, 2013, we have a valuation allowance of $83.2 million recorded against our net deferred tax asset which includes $69.8 million related to our U.S. operations and $13.4 million related to the capital loss carryforward generated by the sale of Hudsons Hope Gas, Ltd., as described in Note 6Discontinued Operations.
A reconciliation of the effective tax rate to the statutory rate for the three months ended June 30, 2013 is as follows:
|
|
Total |
|
|
| |
Amount computed using statutory rates |
|
$ |
14,407,806 |
|
34.00 |
% |
State income taxesnet of federal benefit |
|
1,084,723 |
|
2.56 |
% | |
Reduction of valuation allowance |
|
(15,629,252 |
) |
-36.88 |
% | |
Nondeductible items and other |
|
142,973 |
|
0.33 |
% | |
Income tax provision |
|
$ |
6,250 |
|
0.01 |
% |
A reconciliation of the effective tax rate to the statutory rate for the six months ended June 30, 2013 is as follows:
|
|
Total |
|
|
| |
Amount computed using statutory rates |
|
$ |
12,453,260 |
|
34.00 |
% |
State income taxesnet of federal benefit |
|
876,006 |
|
2.39 |
% | |
Reduction of valuation allowance |
|
(13,472,543 |
) |
-36.78 |
% | |
Nondeductible items and other |
|
155,777 |
|
0.42 |
% | |
Income tax provision |
|
$ |
12,500 |
|
0.03 |
% |
Note 13Common Stock
At June 30, 2013 and December 31, 2012, there were 40,663,554 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 June 30, 2013 and December 31, 2012 were 180,233 and 254,260 shares of restricted stock, respectively. The following table details the activity related to our common stock for the three months ended June 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 |
) |
Common stock outstanding at June 30, 2013 |
|
|
|
40,663,554 |
|
Note 14Series A Convertible Redeemable Preferred Stock
At June 30, 2013 and December 31, 2012, 5,471,610 and 5,305,865 shares of preferred stock were issued and outstanding, respectively. At June 30, 2013, an additional 1,930,222 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 six months ended June 30, 2013:
|
|
Dividend Period |
|
Date Issued |
|
Number of Shares |
|
Balance |
| |
|
|
|
|
|
|
|
|
|
| |
Balance at January 1, 2013 |
|
|
|
|
|
5,305,865 |
|
$ |
35,851,887 |
|
Accretion of Preferred Stock |
|
|
|
|
|
|
|
1,026,373 |
| |
PIK Dividend Issued for Preferred Stock |
|
3/31/13 |
|
4/1/13 |
|
165,745 |
|
1,075,685 |
| |
Balance At June 30, 2013 |
|
|
|
|
|
5,471,610 |
|
$ |
37,953,945 |
|
On June 5, 2013, we declared a quarterly dividend of 170,931 shares of Preferred Stock covering the period April 1, 2013 through June 30, 2013. As those shares were not issued until July 1, 2013, they were not included in the Preferred Stock balance at June 30, 2013. As such, we recorded a dividend payable in Current liabilities in the Consolidated Balance Sheets (Unaudited) at June 30, 2013 at an estimated fair value of $1,367,488.
Note 15Share-Based Awards
As of June 30, 2013, our 2006 Long-Term Incentive Plan (the 2006 Plan) is our only authorized stock-based award plan. Our 2005 Stock Option Plan was terminated on March 11, 2011 as no options granted under the plan remained outstanding at that time. Our 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 Long-Term Incentive Plan vest once the performance criteria have been met. Options granted to our directors vest immediately.
During the three months ended June 30, 2013, we recorded a compensation expense accrual of $60,650 which was allocated as an addition of $6,759 to lease operating expenses and an addition of $53,891 to general and administrative expense. During the six months ended June 30, 2013, we recorded a compensation expense accrual of $119,374 which was allocated as an addition of $13,511 to lease operating expenses and an addition of $105,863 to general and administrative expense. The future compensation cost of all the outstanding awards is $172,100 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 0.61 years.
During the three months ended June 30, 2012, we recorded a compensation expense accrual of $282,350 of which $12,433 was allocated to lease operating expenses, $135,220 was allocated to general and administrative expenses, $131,127 was allocated to restructuring costs, and $3,570 was capitalized to gas properties. During the six months ended June 30, 2012, we recorded a compensation expense accrual of $414,149 of which $22,294 was allocated to lease operating expenses, $240,116 was 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 June 30, 2013:
|
|
Number of |
|
Weighted |
|
Average |
|
Aggregate |
| ||
Outstanding at December 31, 2012 |
|
1,412,739 |
|
$ |
1.11 |
|
|
|
|
| |
Forfeited |
|
(87,846 |
) |
$ |
1.18 |
|
|
|
|
| |
Outstanding at June 30, 2013 |
|
1,324,893 |
|
$ |
1.11 |
|
3.4 |
|
$ |
|
|
Options exercisable at June 30, 2013 |
|
909,208 |
|
$ |
0.99 |
|
3.8 |
|
$ |
|
|
Non-Qualified Stock Options
The table below summarizes non-qualified stock option activity for the three months ended June 30, 2013:
|
|
Number of |
|
Weighted |
|
Average |
|
Aggregate |
| ||
Outstanding at December 31, 2012 |
|
974,765 |
|
$ |
2.33 |
|
|
|
|
| |
Expired |
|
(200,000 |
) |
$ |
2.50 |
|
|
|
|
| |
Outstanding at June 30, 2013 |
|
774,765 |
|
$ |
2.28 |
|
0.9 |
|
$ |
|
|
Options exercisable at June 30, 2013 |
|
733,242 |
|
$ |
2.37 |
|
1.1 |
|
$ |
|
|
Restricted Stock Awards
The table below summarizes non-vested restricted stock awards activity for the three months ended June 30, 2013:
|
|
Number of |
|
Weighted |
| |
Non-vested restricted stock at December 31, 2012 |
|
254,260 |
|
$ |
1.43 |
|
Vested |
|
(72,053 |
) |
$ |
0.70 |
|
Forfeited |
|
(1,974 |
) |
$ |
1.32 |
|
Non-vested restricted stock at June 30, 2013 |
|
180,233 |
|
$ |
1.72 |
|
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 Companys 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 June 30, 2013.
Note 16Commitments 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 June 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.
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Statement Regarding Forward-Looking Information
Managements Discussion and Analysis of Financial Condition and Results of Operations and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on managements beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words believe, anticipate, estimate, expect, intend, may, will, project, forecast, plan, and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to certain risks, uncertainties and assumptions. Certain of these risks are summarized in our 2012 Annual Report on Form 10-K that we filed with the SEC on March 28, 2013, which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.
You should read Managements Discussion and Analysis of Financial Condition and Results of Operations in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2012, which are included in our 2012 Annual Report on Form 10-K.
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 over the last several years. The low natural gas prices in 2012 had pervasive adverse consequences to our business. A borrowing base deficiency under our Credit Agreement was caused by the then low natural gas prices. 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. The new borrowing base was set at the lesser of the total amount of outstanding borrowings under the Credit Agreement and $77.0 million. In connection with this repayment the non-conforming Tranche B portion of total outstanding borrowings has been 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 Companys reserves at June 30, 2013. As of June 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.
Managements current business plan is to continue to evaluate its strategic alternatives. Additionally, management is seeking to divest properties with limited value and will consider additional asset sale opportunities as they arise. Management also remains focused on maintaining compliance with the Credit Agreement, as amended, maintaining production levels, and keeping costs under control.
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/ MMBtu, its lowest in over ten years. Presented below are the NYMEX Settle Prices for the period January 2011 through August 2013 and the NYMEX Forward Curve Prices (as of August 7, 2013) for natural gas for the period September 2013 through December 2013.
Recent Developments
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 normal and customary 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 Companys 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.
GeoMets net interest in the coalbed methane properties in Alabama sold produced approximately 9,700 Mcf of natural gas per day during the month of March 2013, or approximately 29% of GeoMets total production for this time period. As of March 31, 2013 and based on Securities and Exchange Commission guidelines, GeoMets 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 June 30, 2013, we own a total of approximately 93,000 net acres of coalbed methane and oil and gas development rights.
Central Appalachia
Pond Creek and Lasher FieldsWe 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 16.0 MMcf per day for the three and six months ended June 30, 2013. 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 MMBtus and 10,000 MMBtus 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.
Pinnate Horizontal WellsWe 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 7.7 MMcf per day and 8.0 MMcf per day for the three and six months ended June 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 GeoMets 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 June 30, 2013.
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 six months ended June 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 |
|
Six Months Ended |
| ||||||||
|
|
2013 |
|
2012 |
|
2013 |
|
2012 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Gas sales |
|
$ |
12,053 |
|
$ |
7,712 |
|
$ |
22,932 |
|
$ |
17,855 |
|
|
|
|
|
|
|
|
|
|
| ||||
Lease operating expenses |
|
$ |
4,123 |
|
$ |
4,492 |
|
$ |
8,592 |
|
$ |
8,933 |
|
Compression and transportation expenses |
|
1,868 |
|
2,301 |
|
3,707 |
|
4,540 |
| ||||
Production taxes |
|
647 |
|
364 |
|
1,198 |
|
834 |
| ||||
Total production expenses |
|
$ |
6,638 |
|
$ |
7,157 |
|
$ |
13,497 |
|
$ |
14,307 |
|
|
|
|
|
|
|
|
|
|
| ||||
Net sales volumes (Consolidated) (MMcf) |
|
2,908 |
|
3,448 |
|
6,016 |
|
7,078 |
| ||||
Pond Creek field (Central Appalachian Basin) (MMcf) |
|
1,411 |
|
1,459 |
|
2,822 |
|
2,925 |
| ||||
Other Central Appalachian Basin fields (MMcf) |
|
744 |
|
996 |
|
1,539 |
|
2,045 |
| ||||
Gurnee field (Cahaba Basin) (MMcf) |
|
328 |
|
438 |
|
723 |
|
895 |
| ||||
Black Warrior Basin fields (MMcf) |
|
425 |
|
555 |
|
932 |
|
1,213 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Per Mcf data ($/Mcf): |
|
|
|
|
|
|
|
|
| ||||
Average natural gas sales price (Consolidated) |
|
$ |
4.14 |
|
$ |
2.24 |
|
$ |
3.81 |
|
$ |
2.52 |
|
Pond Creek field (Central Appalachian Basin) |
|
$ |
4.14 |
|
$ |
2.26 |
|
$ |
3.87 |
|
$ |
2.61 |
|
Other Central Appalachian Basin fields |
|
$ |
4.18 |
|
$ |
2.14 |
|
$ |
3.77 |
|
$ |
2.38 |
|
Gurnee field (Cahaba Basin) |
|
$ |
4.16 |
|
$ |
2.25 |
|
$ |
3.77 |
|
$ |
2.52 |
|
Black Warrior Basin fields |
|
$ |
4.09 |
|
$ |
2.32 |
|
$ |
3.73 |
|
$ |
2.56 |
|
Average natural gas sales price realized (Consolidated)(1) (2) |
|
$ |
3.23 |
|
$ |
3.78 |
|
$ |
3.89 |
|
$ |
3.95 |
|
Lease operating expenses (Consolidated) |
|
$ |
1.42 |
|
$ |
1.29 |
|
$ |
1.43 |
|
$ |
1.26 |
|
Pond Creek field (Central Appalachian Basin) |
|
$ |
1.11 |
|
$ |
1.05 |
|
$ |
1.15 |
|
$ |
1.04 |
|
Other Central Appalachian Basin fields |
|
$ |
1.68 |
|
$ |
1.41 |
|
$ |
1.69 |
|
$ |
1.42 |
|
Gurnee field (Cahaba Basin) |
|
$ |
2.93 |
|
$ |
2.75 |
|
$ |
2.84 |
|
$ |
2.60 |
|
Black Warrior Basin fields |
|
$ |
0.80 |
|
$ |
0.59 |
|
$ |
0.74 |
|
$ |
0.52 |
|
Compression and transportation expenses (Consolidated) |
|
$ |
0.64 |
|
$ |
0.67 |
|
$ |
0.61 |
|
$ |
0.64 |
|
Pond Creek field (Central Appalachian Basin) |
|
$ |
0.67 |
|
$ |
0.64 |
|
$ |
0.62 |
|
$ |
0.58 |
|
Other Central Appalachian Basin fields |
|
$ |
1.02 |
|
$ |
1.14 |
|
$ |
1.02 |
|
$ |
1.16 |
|
Gurnee field (Cahaba Basin) |
|
$ |
0.26 |
|
$ |
0.23 |
|
$ |
0.29 |
|
$ |
0.26 |
|
Black Warrior Basin fields |
|
$ |
0.18 |
|
$ |
0.21 |
|
$ |
0.18 |
|
$ |
0.19 |
|
Production taxes (Consolidated) |
|
$ |
0.22 |
|
$ |
0.10 |
|
$ |
0.20 |
|
$ |
0.12 |
|
Pond Creek field (Central Appalachian Basin) |
|
$ |
0.22 |
|
$ |
0.13 |
|
$ |
0.21 |
|
$ |
0.15 |
|
Other Central Appalachian Basin fields |
|
$ |
0.22 |
|
$ |
0.06 |
|
$ |
0.18 |
|
$ |
0.06 |
|
Gurnee field (Cahaba Basin) |
|
$ |
0.21 |
|
$ |
0.09 |
|
$ |
0.18 |
|
$ |
0.10 |
|
Black Warrior Basin fields |
|
$ |
0.23 |
|
$ |
0.14 |
|
$ |
0.23 |
|
$ |
0.15 |
|
Total production expenses (Consolidated) |
|
$ |
2.28 |
|
$ |
2.06 |
|
$ |
2.24 |
|
$ |
2.02 |
|
Pond Creek field (Central Appalachian Basin) |
|
$ |
2.00 |
|
$ |
1.82 |
|
$ |
1.98 |
|
$ |
1.77 |
|
Other Central Appalachian Basin fields |
|
$ |
2.92 |
|
$ |
2.61 |
|
$ |
2.89 |
|
$ |
2.64 |
|
Gurnee field (Cahaba Basin) |
|
$ |
3.40 |
|
$ |
3.07 |
|
$ |
3.31 |
|
$ |
2.96 |
|
Black Warrior Basin fields |
|
$ |
1.21 |
|
$ |
0.94 |
|
$ |
1.13 |
|
$ |
0.86 |
|
Depletion (Consolidated) |
|
$ |
0.48 |
|
$ |
0.92 |
|
$ |
0.46 |
|
$ |
0.95 |
|
(1) Average natural gas sales price realized includes the effects of realized gains and losses on derivative contracts.
(2) Average natural gas sales prices realized for the three and six months ended June 30, 2013 would have been $3.65/Mcf and $4.09/Mcf when excluding $1.2 million in realized losses on derivative contracts related to natural gas swap positions terminated in order to prevent the Company from being over-hedged after the closing of the sale of its coalbed methane properties in Alabama.
Results of Operations
Three months ended June 30, 2013 compared with three months ended June 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 |
|
|
| ||||
|
|
2013 |
|
2012 |
|
Change |
| ||
|
|
(in thousands) |
| ||||||
Gas sales volume (MMcf) |
|
2,908 |
|
3,448 |
|
-16 |
% | ||
Gas sales |
|
$ |
12,053 |
|
$ |
7,712 |
|
56 |
% |
Lease operating expenses |
|
$ |
4,123 |
|
$ |
4,492 |
|
-8 |
% |
Compression expense |
|
$ |
1,189 |
|
$ |
1,256 |
|
-5 |
% |
Transportation expense |
|
$ |
679 |
|
$ |
1,045 |
|
-35 |
% |
Production taxes |
|
$ |
647 |
|
$ |
364 |
|
78 |
% |
Depreciation, depletion and amortization |
|
$ |
1,371 |
|
$ |
3,290 |
|
-58 |
% |
Impairment of gas properties |
|
$ |
|
|
$ |
42,256 |
|
NM |
|
General and administrative |
|
$ |
1,409 |
|
$ |
1,366 |
|
3 |
% |
Realized losses (gains) on derivative contracts |
|
$ |
2,647 |
|
$ |
(5,311 |
) |
NM |
|
Unrealized (gains) losses from the change in market value of open derivative contracts |
|
$ |
(6,797 |
) |
$ |
10,203 |
|
NM |
|
Gain on the sale of Properties in Alabama |
|
$ |
37,136 |
|
$ |
|
|
NM |
|
Interest expense |
|
$ |
1,559 |
|
$ |
1,268 |
|
23 |
% |
Income tax expense |
|
$ |
6 |
|
$ |
6 |
|
|
% |
NM-Not Meaningful
Gas sales. Gas sales increased by $4.3 million, or 56%, to $12.1 million compared to the prior year period. The increase in gas sales was the result of a 85% increase in natural gas prices, excluding hedging transactions, partially offset by of 11% lower daily production volumes and 5% lower total volume resulting from the sale of our Alabama properties on June 14, 2013.
Lease operating expenses. Lease operating expenses remained flat compared to the prior year period.
Compression expense. Compression expense remained flat compared to the prior year period.
Transportation expense. Transportation expense decreased by $0.4 million, or 35%, to $0.7 million compared to the prior year period. The decrease was primarily due to contract expirations or renegotiations.
Production taxes. Production taxes remained flat compared to the prior year period. However, we expect future production taxes to increase over time as our West Virginia exemptions diminish.
Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $1.9 million, or 58%, to $1.4 million compared to the prior year period. This decrease was primarily due to the $95.7 million in impairments recorded to our gas properties in 2012.
General and administrative. General and administrative expense remained flat compared to the prior year period. Included in general and administrative expense was a decrease in professional fees, offset by non-recurring executive compensation. In November 2012, the Compensation Committee approved the payment of a contingent bonus in the amount of $0.4 million to be paid to the named executive officers in connection with the elimination of the borrowing base deficiency that existed under the Companys Credit Agreement.
Realized losses (gains) on derivative contracts. Realized losses on derivative contracts were $2.6 million in the current year period of which $1.2 million was related to natural gas swap positions terminated in order to prevent the Company from being over-hedged after the closing of the sale of its coalbed methane properties in Alabama. Realized losses represent net cash flow settlements paid to the contract counterparty, while realized gains represent net cash flow settlements paid to us from the contract counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.
Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized gains on open derivative contracts were $6.8 million in the current year period. Unrealized gains and losses are non-cash transactions that occur when the corresponding asset or liability derivative contracts are marked-to-market at the end of each reporting period.
Gain on the sale of 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, recording a gain on the sale of $37.1 million, as described in Note 2 Sale of Coalbed Methane Properties in Alabama in the Notes to Consolidated Financial Statements (Unaudited).
Interest expense. Interest expense increased by $0.3 million, or 23%, to $1.6 million compared to the prior year period. The increase was primarily due to average interest on the borrowings increasing to 3.83% per annum in the current year period from 2.99% per annum in the prior year period. The increased rates resulted from the August 2012 amendment to the Credit Agreement.
Income tax expense. The income tax expense in the current year period was different than the amount computed using the statutory rate primarily due to a $15.6 million reduction of the valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:
|
|
Total |
|
|
| |
Amount computed using statutory rates |
|
$ |
14,407,806 |
|
34.00 |
% |
State income taxesnet of federal benefit |
|
1,084,723 |
|
2.56 |
% | |
Reduction of valuation allowance |
|
(15,629,252 |
) |
-36.88 |
% | |
Nondeductible items and other |
|
142,973 |
|
0.33 |
% | |
Income tax provision |
|
$ |
6,250 |
|
0.01 |
% |
Six months ended June 30, 2013 compared with six months ended June 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.
|
|
Six Months Ended |
|
|
| ||||
|
|
2013 |
|
2012 |
|
Change |
| ||
|
|
(in thousands) |
| ||||||
Gas sales volume (MMcf) |
|
6,016 |
|
7,078 |