x
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______ TO ______
|
Nevada
|
74-2584033
|
|
(State of Incorporation)
|
(I.R.S. Employer Identification No.)
|
18803 Meisner Drive, San Antonio, TX 78258
|
(Address of principal executive offices) (Zip Code)
|
210-490-4788
|
(Registrant’s telephone number, including area code)
|
Not Applicable
|
(Former name, former address and former fiscal year, if changed since last report)
|
Large accelerated filer o
|
Accelerated filer x
|
Non-accelerated filer o
(Do not mark if a smaller reporting company)
|
Smaller reporting company o
|
|
·
|
our success in development, exploitation and exploration activities;
|
|
·
|
our ability to procure services and equipment for our drilling and completion activities;
|
|
·
|
the prices we receive for our oil and gas and the effectiveness of our hedging activities;
|
|
·
|
our ability to make planned capital expenditures;
|
|
·
|
declines in our production of oil and gas;
|
|
·
|
the availability of capital;
|
|
·
|
political and economic conditions in oil producing countries, especially those in the Middle East;
|
|
·
|
price and availability of alternative fuels;
|
|
·
|
our restrictive debt covenants;
|
|
·
|
our acquisition and divestiture activities;
|
|
·
|
weather conditions and events;
|
|
·
|
the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
|
|
·
|
other factors discussed elsewhere in this report.
|
PART I
|
||
FINANCIAL INFORMATION
|
||
ITEM 1 -
|
Financial Statements
|
|
6 | ||
8 | ||
9 | ||
10 | ||
ITEM 2 -
|
23 | |
ITEM 3 -
|
37 | |
ITEM 4 -
|
38 | |
PART II
|
||
OTHER INFORMATION
|
||
ITEM 1 -
|
39 | |
ITEM 1a -
|
39 | |
ITEM 2 -
|
39 | |
ITEM 3 -
|
39 | |
ITEM 4 -
|
[Removed and Reserved]
|
39 |
ITEM 5 -
|
39 | |
ITEM 6 -
|
40 | |
Signatures
|
||
June 30,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
(Unaudited)
|
||||||||
Assets
|
||||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | 4,151 | $ | 99 | ||||
Accounts receivable, net:
|
||||||||
Joint owners
|
1,538 | 5,145 | ||||||
Oil and gas production
|
9,151 | 6,958 | ||||||
Other
|
298 | 642 | ||||||
10,987 | 12,745 | |||||||
Derivative asset – current
|
6,964 | 6,941 | ||||||
Assets held for sale
|
— | 8,457 | ||||||
Other current assets
|
415 | 396 | ||||||
Total current assets
|
22,517 | 28,638 | ||||||
Property and equipment:
|
||||||||
Oil and gas properties, full cost method of accounting:
|
||||||||
Proved
|
459,705 | 434,858 | ||||||
Unproved properties excluded from depletion
|
1,911 | 1,085 | ||||||
Other property and equipment
|
11,742 | 11,536 | ||||||
Total
|
473,358 | 447,479 | ||||||
Less accumulated depreciation, depletion, and amortization
|
(337,561 | ) | (330,231 | ) | ||||
Total property and equipment – net
|
135,797 | 117,248 | ||||||
|
||||||||
Investment in joint venture
|
25,545 | 24,027 | ||||||
Deferred financing fees, net
|
3,751 | 3,494 | ||||||
Derivative asset – long-term
|
6,680 | 8,674 | ||||||
Other assets
|
858 | 828 | ||||||
Total assets
|
$ | 195,148 | $ | 182,909 |
June 30,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
(Unaudited)
|
||||||||
Liabilities and Stockholders’ Equity (Deficit)
|
||||||||
Current liabilities:
|
||||||||
Accounts payable
|
$ | 13,549 | $ | 23,589 | ||||
Oil and gas production payable
|
6,847 | 3,000 | ||||||
Accrued interest
|
29 | 277 | ||||||
Other accrued expenses
|
1,574 | 779 | ||||||
Derivative liability – current
|
11,788 | 9,742 | ||||||
Current maturities of long-term debt
|
157 | 152 | ||||||
Total current liabilities
|
33,944 | 37,539 | ||||||
Long-term debt, excluding current maturities
|
94,860 | 140,940 | ||||||
Derivative liability – long-term
|
10,752 | 11,672 | ||||||
Future site restoration
|
8,077 | 7,734 | ||||||
Total liabilities
|
147,633 | 197,885 | ||||||
Stockholders’ Equity (Deficit)
|
||||||||
Preferred stock, par value $.01 per share, authorized 1,000,000 shares; -0- issued and outstanding
|
— | — | ||||||
Common stock, par value $.01 per share, authorized 200,000,000 shares;91,740,465 and 76,427,561 issued and outstanding
|
917 | 764 | ||||||
Additional paid-in capital
|
247,523 | 184,223 | ||||||
Accumulated deficit
|
(201,290 | ) | (200,208 | ) | ||||
Accumulated other comprehensive income
|
365 | 245 | ||||||
Total stockholders’ equity (deficit)
|
47,515 | (14,976 | ) | |||||
Total liabilities and stockholders’ equity (deficit)
|
$ | 195,148 | $ | 182,909 |
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Revenue:
|
||||||||||||||||
Oil and gas production revenues
|
$ | 16,653 | $ | 14,646 | $ | 30,500 | $ | 30,509 | ||||||||
Rig revenues
|
297 | 259 | 492 | 520 | ||||||||||||
Other
|
3 | 4 | 4 | 6 | ||||||||||||
16,953 | 14,909 | 30,996 | 31,035 | |||||||||||||
Operating costs and expenses:
|
||||||||||||||||
Lease operating expenses
|
5,601 | 5,040 | 9,622 | 9,627 | ||||||||||||
Production taxes
|
1,426 | 1,525 | 2,680 | 3,227 | ||||||||||||
Depreciation, depletion, and amortization
|
3,780 | 4,433 | 7,210 | 8,674 | ||||||||||||
Rig operations
|
262 | 193 | 451 | 390 | ||||||||||||
General and administrative (including stock-based compensation of $706, $537, $1,069 and $847)
|
2,446 | 2,191 | 5,092 | 4,332 | ||||||||||||
13,515 | 13,382 | 25,055 | 26,250 | |||||||||||||
Operating income
|
3,438 | 1,527 | 5,941 | 4,785 | ||||||||||||
Other (income) expense:
|
||||||||||||||||
Interest income
|
(2 | ) | (2 | ) | (4 | ) | (4 | ) | ||||||||
Interest expense
|
1,336 | 2,252 | 2,941 | 4,586 | ||||||||||||
Amortization of deferred financing fee
|
770 | 513 | 1,270 | 1,322 | ||||||||||||
(Gain) loss on derivative contracts (unrealized $(7,959), $(5,941), $3,019 and $(17,636))
|
(6,846 | ) | (6,550 | ) | 4,247 | (17,527 | ) | |||||||||
Equity in (income) loss of joint venture
|
(769 | ) | — | (1,518 | ) | — | ||||||||||
Other
|
12 | 14 | 87 | (75 | ) | |||||||||||
(5,499 | ) | (3,773 | ) | 7,023 | (11,698 | ) | ||||||||||
Net income (loss)
|
$ | 8,937 | $ | 5,300 | $ | (1,082 | ) | $ | 16,483 | |||||||
Net income (loss) per common share – basic
|
$ | 0.10 | $ | 0.07 | $ | (0.01 | ) | $ | 0.22 | |||||||
Net income (loss) per common share – diluted
|
$ | 0.10 | $ | 0.07 | $ | (0.01 | ) | $ | 0.21 |
Six Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
Operating Activities
|
||||||||
Net (loss) income
|
$ | (1,082 | ) | $ | 16,483 | |||
Adjustments to reconcile net (loss) income to net
|
||||||||
cash provided by operating activities:
|
||||||||
Equity in income of joint venture
|
(1,518 | ) | — | |||||
Change in derivative fair value
|
3,097 | (18,477 | ) | |||||
Depreciation, depletion, and amortization
|
7,210 | 8,674 | ||||||
Amortization of deferred financing fees
|
1,270 | 1,322 | ||||||
Accretion of future site restoration
|
221 | 271 | ||||||
Stock-based compensation
|
1,069 | 847 | ||||||
Other non-cash expenses
|
— | 24 | ||||||
Changes in operating assets and liabilities:
|
||||||||
Accounts receivable
|
1,770 | 149 | ||||||
Other
|
69 | (260 | ) | |||||
Accounts payable and accrued expenses
|
(5,527 | ) | (3,285 | ) | ||||
Net cash provided by operating activities
|
6,579 | 5,748 | ||||||
Investing Activities
|
||||||||
Capital expenditures, including purchases and development of properties
|
(25,622 | ) | (8,592 | ) | ||||
Proceeds from sale of oil and gas properties
|
8,457 | 11,008 | ||||||
Net cash (used in) provided by investing activities
|
(17,165 | ) | 2,416 | |||||
Financing Activities
|
||||||||
Proceeds from long-term borrowings
|
12,000 | 2,000 | ||||||
Payments on long-term borrowings
|
(58,075 | ) | (9,270 | ) | ||||
Deferred financing fees
|
(1,527 | ) | (139 | ) | ||||
Proceeds from issuance of common stock
|
62,224 | — | ||||||
Other
|
16 | (22 | ) | |||||
Net cash provided by (used in) financing activities
|
14,638 | (7,431 | ) | |||||
Effect of exchange rate changes on cash
|
— | — | ||||||
Increase in cash
|
4,052 | 733 | ||||||
Cash and equivalents, at beginning of period
|
99 | 1,861 | ||||||
Cash and equivalents, at end of period
|
$ | 4,151 | $ | 2,594 | ||||
Supplemental disclosure of cash flow information:
|
||||||||
Interest paid
|
$ | 2,968 | $ | 4,314 |
Number
of
Shares
|
Weighted
Average
Option
Exercise
Price Per
Share
|
Weighted
Average
Grant
Date Fair
Value
Per Share
|
Aggregate
Intrinsic
Value
|
||||||||||
Outstanding, December 31, 2010
|
4,820
|
$
|
2.23
|
$
|
1.60
|
$
|
6,880
|
||||||
Granted
|
601
|
$
|
4.64
|
$
|
3.31
|
1,988
|
|||||||
Exercised
|
(292
|
) |
$
|
1.81
|
$
|
1.28
|
(322
|
)
|
|||||
Expired or canceled
|
(26
|
) |
$
|
1.83
|
$
|
1.31
|
(34
|
)
|
|||||
Outstanding, June 30, 2011
|
5,103
|
$
|
2.53
|
$
|
1.81
|
$
|
8,512
|
Expected dividend yield
|
0 |
%
|
|||
Volatility
|
79.58 |
%
|
|||
Risk free interest rate
|
2.48 |
%
|
|||
Expected life
|
6.5 |
Years
|
|||
Fair value of options granted (in thousands)
|
$ | 1,988 | |||
Weighted average grant date fair value per share of options granted
|
$ | 3.31 |
June 30,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
Options exercisable
|
2,517 | 2,288 |
Number
of
Shares
|
Weighted
Average
Grant Date
Fair Value
Per Share
|
|||||||
Unvested, December 31, 2010
|
400 | $ | 2.02 | |||||
Granted
|
41 | 4.69 | ||||||
Vested/Released
|
(120 | ) | 1.83 | |||||
Forfeited
|
(1 | ) | 2.59 | |||||
Unvested, June 30, 2011
|
320 | $ | 2.43 |
June 30, 2011
|
December 31, 2010
|
|||||||
Beginning asset retirement obligation
|
$ | 7,734 | $ | 10,326 | ||||
Settled
|
(2 | ) | (290 | ) | ||||
Revisions
|
(14 | ) | (83 | ) | ||||
New wells placed on production and other
|
139 | 64 | ||||||
Deletions related to property disposals
|
(1 | ) | (2,799 | ) | ||||
Accretion expense
|
221 | 516 | ||||||
Ending asset retirement obligation
|
$ | 8,077 | $ | 7,734 |
Balance Sheet:
|
As of
June 30, 2011
|
As of
December 31, 2010
|
||||||
Assets:
|
||||||||
Current assets
|
$ | 14,275 | $ | 19,625 | ||||
Oil and gas properties
|
53,294 | 31,753 | ||||||
Other assets
|
41 | 45 | ||||||
Total assets
|
$ | 67,610 | $ | 51,423 | ||||
Liabilities and Member Capital:
|
||||||||
Current liabilities
|
$ | 5,270 | $ | 3,368 | ||||
Other liabilities
|
9 | — | ||||||
Member capital
|
62,331 | 48,055 | ||||||
Total liabilities and member capital
|
$ | 67,610 | $ | 51,423 |
Statement of Operations:
|
Three Months Ended June 30, 2011
|
Six Months
Ended June 30, 2011
|
||||||
Revenue
|
$ | 3,758 | $ | 6,855 | ||||
Operating expenses
|
1,544 | 3,148 | ||||||
Other (income) expense
|
(4 | ) | (9 | ) | ||||
Net income
|
$ | 2,218 | $ | 3,716 |
June 30, 2011
|
December 31, 2010
|
|||||||
Credit facility
|
$ | 90,000 | $ | 136,000 | ||||
Real estate lien note
|
5,017 | 5,092 | ||||||
95,017 | 141,092 | |||||||
Less current maturities
|
(157 | ) | (152 | ) | ||||
$ | 94,860 | $ | 140,940 |
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Numerator:
|
||||||||||||||||
Net income (loss)
|
$ | 8,937 | $ | 5,300 | $ | (1,082 | ) | $ | 16,483 | |||||||
Denominator:
|
||||||||||||||||
Denominator for basic income (loss) per share -
|
||||||||||||||||
Weighted-average shares
|
91,409 | 75,850 | 88,653 | 75,824 | ||||||||||||
Effect of dilutive securities:
|
||||||||||||||||
Stock options and warrants
|
2,097 | 1,298 | — | 1,228 | ||||||||||||
Denominator for diluted income (loss) per share - adjusted weighted-average shares and assumed conversions
|
93,506 | 77,148 | 88,653 | 77,052 | ||||||||||||
Net income (loss) per common share – basic
|
$ | 0.10 | $ | 0.07 | $ | (0.01 | ) | $ | 0.22 | |||||||
Net income (loss) per common share – diluted
|
$ | 0.10 | $ | 0.07 | $ | (0.01 | ) | $ | 0.21 |
Fixed Price Swap
|
||||||||||||||||
Oil
|
Gas
|
|||||||||||||||
Contract Periods
|
Daily Volume (Bbl)
|
Swap Price (per Bbl)
|
Daily Volume (MMBtu)
|
Swap Price (per MMBtu)
|
||||||||||||
2011
|
1,035 | $ | 76.61 | 9,580 | $ | 6.52 | ||||||||||
2012
|
946 | $ | 70.89 | 8,303 | $ | 6.77 | ||||||||||
2013
|
705 | $ | 80.79 | 5,962 | $ | 6.84 |
June 30, 2011
|
December 31, 2010
|
|||||||||
Balance Sheet
Location
|
Fair Value
|
Balance Sheet
Location
|
Fair Value
|
|||||||
NYMEX-based fixed price derivative contracts
|
Derivative asset - current
|
$ | 6,964 |
Derivative asset - current
|
$ | 6,941 | ||||
NYMEX-based fixed price derivative contracts
|
Derivative asset – long-term
|
$ | 6,680 |
Derivative asset – long-term
|
$ | 8,674 | ||||
NYMEX-based fixed price derivative contracts
|
Derivative liability - current
|
$ | 9,150 |
Derivative liability - current
|
$ | 6,394 | ||||
NYMEX-based fixed price derivative contracts
|
Derivative liability – long-term
|
$ | 10,752 |
Derivative liability – long-term
|
$ | 11,672 | ||||
Interest rate swap
|
Derivative liability - current
|
$ | 2,638 |
Derivative liability - current
|
$ | 3,348 |
|
·
|
Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
|
·
|
Level 2 – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
|
|
·
|
Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.
|
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs (Level 3)
|
Balance as of
June 30,
2011
|
|||||||||||||
Assets
|
||||||||||||||||
Investment in common stock
|
$ | 177 | $ | — | $ | — | $ | 177 | ||||||||
NYMEX Fixed Price Derivative contracts
|
— | 13,644 | — | 13,644 | ||||||||||||
Total Assets
|
$ | 177 | $ | 13,644 | $ | — | $ | 13,821 | ||||||||
Liabilities
|
||||||||||||||||
NYMEX Fixed Price Derivative contracts
|
$ | — | $ | 19,902 | $ | — | $ | 19,902 | ||||||||
Interest Rate Swaps
|
— | — | 2,638 | 2,638 | ||||||||||||
Total Liabilities
|
$ | — | $ | 19,902 | $ | 2,638 | $ | 22,540 |
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs (Level 3)
|
Balance as of
December 31,
2010
|
|||||||||||||
Assets:
|
||||||||||||||||
Investment in common stock
|
$ | 181 | $ | — | $ | — | $ | 181 | ||||||||
NYMEX Fixed Price Derivative contracts
|
— | 15,615 | — | 15,615 | ||||||||||||
Total Assets
|
$ | 181 | $ | 15,615 | $ | — | $ | 15,796 | ||||||||
Liabilities:
|
||||||||||||||||
NYMEX Fixed Price Derivative contracts
|
$ | — | $ | 18,066 | $ | — | $ | 18,066 | ||||||||
Interest Rate Swaps
|
— | — | 3,348 | 3,348 | ||||||||||||
Total Liabilities
|
$ | — | $ | 18,066 | $ | 3,348 | $ | 21,414 |
Derivative Assets
(Liabilities) -
net
|
||||||||
Three Months Ended
June 30, 2011
|
Six Months Ended
June 30, 2011
|
|||||||
Balance Beginning of period
|
$ | (2,897 | ) | $ | (3,348 | ) | ||
Total realized and unrealized losses included in change in net liability
|
(300 | ) | (448 | ) | ||||
Settlements during the period
|
559 | 1,158 | ||||||
Balance June 30, 2011
|
$ | (2,638 | ) | $ | (2,638 | ) |
Three Months Ended June 30, 2011
|
||||||||||||||||
U.S
|
Canada
|
Corporate
|
Total
|
|||||||||||||
Revenues:
|
||||||||||||||||
Oil and gas production
|
$ | 16,136 | $ | 517 | $ | — | $ | 16,653 | ||||||||
Rig revenue
|
297 | — | — | 297 | ||||||||||||
Other
|
— | — | 3 | 3 | ||||||||||||
16,433 | 517 | 3 | 16,953 | |||||||||||||
Expenses (income):
|
||||||||||||||||
Lease operating
|
5,410 | 191 | — | 5,601 | ||||||||||||
Production taxes
|
1,426 | — | — | 1,426 | ||||||||||||
Depreciation, depletion and amortization
|
3,488 | 229 | 63 | 3,780 | ||||||||||||
General and administrative
|
395 | 159 | 1,892 | 2,446 | ||||||||||||
Rig operations
|
262 | — | — | 262 | ||||||||||||
Net interest
|
220— | 1 | 1,113 | 1,334 | ||||||||||||
Amortization of deferred financing fees
|
— | — | 770 | 770 | ||||||||||||
Equity in income of joint venture
|
— | — | (769 | ) | (769 | ) | ||||||||||
Gain on derivative contracts
|
— | — | (6,846 | ) | (6,846 | ) | ||||||||||
Other
|
— | — | 12 | 12 | ||||||||||||
11,201 | 580 | (3,765 | ) | 8,016 | ||||||||||||
Net income (loss)
|
$ | 5,232 | $ | (63 | ) | $ | 3,768 | $ | 8,937 |
Six Months Ended June 30, 2011
|
||||||||||||||||
U.S
|
Canada
|
Corporate
|
Total
|
|||||||||||||
Revenues:
|
||||||||||||||||
Oil and gas production
|
$ | 29,794 | $ | 706 | $ | — | $ | 30,500 | ||||||||
Rig revenue
|
492 | — | — | 492 | ||||||||||||
Other
|
— | — | 4 | 4 | ||||||||||||
30,286 | 706 | 4 | 30,996 | |||||||||||||
Expenses (income):
|
||||||||||||||||
Lease operating
|
9,296 | 326 | — | 9,622 | ||||||||||||
Production taxes
|
2,680 | — | — | 2,680 | ||||||||||||
Depreciation, depletion and amortization
|
6,761 | 324 | 125 | 7,210 | ||||||||||||
General and administrative
|
911 | 378 | 3,803 | 5,092 | ||||||||||||
Rig operations
|
451 | — | — | 451 | ||||||||||||
Net interest
|
220 | 1 | 2,716 | 2,937 | ||||||||||||
Amortization of deferred financing fees
|
— | — | 1,270 | 1,270 | ||||||||||||
Equity in income of joint venture
|
— | — | (1,518 | ) | (1,518 | ) | ||||||||||
Loss on derivative contracts
|
— | — | 4,247 | 4,247 | ||||||||||||
Other
|
— | — | 87 | 87 | ||||||||||||
20,319 | 1,029 | 10,730 | 32,078 | |||||||||||||
Net income (loss)
|
$ | 9,967 | $ | (323 | ) | $ | (10,726 | ) | $ | (1,082 | ) |
Segment Assets:
|
June 30,
2011
|
December 31,
2010
|
||||||
United States
|
$ | 139,010 | $ | 152,599 | ||||
Canada
|
6,484 | 4,393 | ||||||
Corporate
|
49,654 | 25,917 | ||||||
$ | 195,148 | $ | 182,909 |
|
·
|
commodity prices and the effectiveness of our hedging arrangements;
|
|
·
|
total sales volumes of oil and gas;
|
|
·
|
the availability of, and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
|
|
·
|
interest rates on borrowings; and
|
|
·
|
the level and success of exploration and development activity.
|
|
|
|
·
|
basis differentials which are dependent on actual delivery location;
|
|
·
|
adjustments for BTU content; and
|
|
·
|
gathering, processing and transportation costs.
|
Fixed Price Swap
|
||||||||||||||||
Oil
|
Gas
|
|||||||||||||||
Contract Periods
|
Daily Volume (Bbl)
|
Swap Price (per Bbl)
|
Daily Volume (MMBtu)
|
Swap Price (per MMBtu)
|
||||||||||||
2011
|
1,035 | $ | 76.61 | 9,580 | $ | 6.52 | ||||||||||
2012
|
946 | $ | 70.89 | 8,303 | $ | 6.77 | ||||||||||
2013
|
705 | $ | 80.79 | 5,962 | $ | 6.84 |
·
|
In McKenzie County, North Dakota, we drilled the Stenehjem 27-34 1H to a total measured depth of 16,504 feet, including a 5,965 foot lateral in the middle Bakken formation, and completed the well with a 17-stage fracture stimulation. The well was placed on production in late June and in 44 days the well has produced (on a restricted choke) 20,000 barrels of oil, 32.2 MMcf of wellhead gas which yields 2,700 barrels of natural gas liquids and 23.3 MMcf of residue gas for a total of 26,500 barrels of oil equivalent, or an average of 600 barrels of oil equivalent per day. For the past three days, the well averaged 615 barrels of oil equivalent per day on a 21/64-inch choke with 750 psi of flowing pressure. We own a 79% working interest in this well.
|
·
|
In various counties in North Dakota and Montana, fourteen non-operated horizontal wells, targeting the Bakken or Three Forks formation, in which we own a working interest are currently in progress or recently placed on-line. Seven gross (0.35 net) wells went on production in June or July, three gross (0.08 net) wells have been fracture stimulated and are currently cleaning up, one gross (0.36 net) well is waiting on completion, one gross (0.01 net) well is currently drilling and two gross (0.05 net) wells are waiting on a drilling rig. Since January 2010, we have elected to participate in 19 gross (1.00 net) non-operated wells in the Bakken / Three Forks play.
|
·
|
In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled, completed and are currently waiting on production facilities. Early production testing of these wells has yielded flow rates in excess of 1,000 barrels of oil per day each.
|
·
|
In early July, we announced the purchase of a drilling rig that is in the process of being refurbished. After completion, the rig will be mobilized to McKenzie County, North Dakota and it is anticipated that the rig will begin drilling on the first pad site in October.
|
·
|
In Campbell and Niobrara Counties, Wyoming, a two well oil development program is scheduled to begin this fall. One of these horizontal wells will target the Niobrara formation and one will target the Turner formation. We own a 100% working interest in each of these wells.
|
·
|
We currently own a 41% equity interest in Blue Eagle, a joint venture between Abraxas and Rock Oil Company, LLC. On June 29, 2011, Rock Oil contributed an additional $11 million to the joint venture and Blue Eagle purchased approximately 2,487 net acres in McMullen County, Texas in the oil window of the play.
|
·
|
In DeWitt County, Texas, Blue Eagle’s first well, the T-Bird 1H, continues to outperform expectations and is currently producing 930 barrels of oil equivalent per day, which is comprised of 185 barrels of condensate, 300 barrels of natural gas liquids and 2.7 MMcf of residue gas. The well has produced approximately 230,000 barrels of oil equivalent during its first 180 days on production. Blue Eagle owns a 100% working interest in this well.
|
·
|
In DeWitt County, Texas, Blue Eagle participated in a non-operated horizontal well with its 43.9% working interest. The Matejek Gas Unit 1 was drilled to a total measured depth of 17,865 feet, including a 3,600 foot lateral, and completed with a 14-stage fracture stimulation. The well is currently shut-in waiting on pipeline hookup which is expected to be completed later this month.
|
·
|
In Atascosa County, Texas, the Grass Farms 1H is currently drilling the lateral at a total measured depth of 13,150 feet towards a total measured depth of 13,380 feet, including a 6,000 foot lateral. A fracture stimulation date has been secured for this well in September, a month later than originally anticipated. Blue Eagle owns a 100% working interest in this well.
|
·
|
In Nolan County, Texas, the Spires 126 2H was drilled to a total measured depth of 9,000 feet, including a 2,000 foot lateral, and completed open hole and un-stimulated. The well was recently placed on-line and during the first 20 days of production, the well averaged 125 barrels of oil equivalent per day, which was comprised of 47 barrels of oil, 46 barrels of natural gas liquids and 210 Mcf of residue gas. We own a 100% working interest in this well.
|
·
|
In Coke County, Texas, the Sadie #2A was drilled to a total vertical depth of 6,425 feet and is waiting on completion and the Sadie #1B is currently drilling below 4,600 feet towards a total vertical depth of 6,500 feet. These two delineation wells are targeting the Canyon Sands. We own a 100% working interest in these wells.
|
·
|
In Reeves County, Texas, we previously announced that we had acquired an additional 640 net acres, for a total of approximately 3,000 net acres, in the emerging Wolfbone play. Two wells directly adjacent to our acreage are currently being drilled by the industry.
|
·
|
In Alberta, Canada, the Twining 6-11 was drilled to a total measured depth of 8,900 feet, including a 3,025 foot lateral, and is waiting on completion and the Twining 6-12 recently reached total measured depth of 9,150 feet, including a 3,380 foot lateral. These two wells are targeting the Pekisko formation. Canadian Abraxas owns a 100% working interest in each of these wells.
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Operating revenue:
|
||||||||||||||||
Oil sales (1)
|
$ | 12,278 | $ | 9,005 | $ | 22,163 | $ | 17,783 | ||||||||
Gas sales (1)
|
4,101 | 5,578 | 7,873 | 12,579 | ||||||||||||
NGL sales
|
274 | 63 | 464 | 147 | ||||||||||||
Rig operations
|
297 | 259 | 492 | 520 | ||||||||||||
Other
|
3 | 4 | 4 | 6 | ||||||||||||
$ | 16,953 | $ | 14,909 | $ | 30,996 | $ | 31,035 | |||||||||
Operating income
|
$ | 3,438 | $ | 1,527 | $ | 5,941 | $ | 4,785 | ||||||||
Oil sales (MBbl)
|
127 | 128 | 243 | 249 | ||||||||||||
Gas sales (MMcf)
|
1,058 | 1,444 | 2,099 | 2,882 | ||||||||||||
NGL sales (MBbl)
|
5 | 2 | 9 | 3 | ||||||||||||
Average oil sales price ($/Bbl) (1)
|
$ | 96.77 | $ | 70.60 | $ | 91.21 | $ | 71.53 | ||||||||
Average gas sales price ($/Mcf) (1)
|
$ | 3.88 | $ | 3.86 | $ | 3.75 | $ | 4.36 | ||||||||
Average NGL sales price ($/Bbl)
|
$ | 52.28 | $ | 38.58 | $ | 50.28 | $ | 43.18 |
|
(1)
|
Before the impact of derivative activities.
|
Three Months Ended
June 30, 2011
|
||||
Oil sales (MBbl)
|
8 | |||
Gas sales (MMcf)
|
126 | |||
NGL sales (MBbl)
|
12 | |||
Average oil sales price ($/Bbl)
|
$ | 93.43 | ||
Average gas sales price ($/Mcf)
|
$ | 4.36 | ||
Average NGL sales price ($/Bbl)
|
$ | 46.69 |
|
Six Months Ended
June 30, 2011
|
|||
Oil sales (MBbl)
|
15 | |||
Gas sales (MMcf)
|
233 | |||
NGL sales (MBbl)
|
24 | |||
Average oil sales price ($/Bbl)
|
$ | 89.50 | ||
Average gas sales price ($/Mcf)
|
$ | 4.21 | ||
Average NGL sales price ($/Bbl)
|
$ | 44.92 |
|
·
|
the development of existing properties, including drilling and completion costs of wells;
|
|
·
|
acquisition of interests in additional oil and gas properties; and
|
|
·
|
production and transportation facilities.
|
Six Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
Expenditure category:
|
||||||||
Development
|
$ | 25,422 | $ | 8,423 | ||||
Facilities and other
|
200 | 169 | ||||||
Total
|
$ | 25,622 | $ | 8,592 |
Six Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
Net cash provided by operating activities
|
$ | 6,579 | $ | 5,748 | ||||
Net cash (used in) provided by investing activities
|
(17,165 | ) | 2,416 | |||||
Net cash provided by (used in) financing activities
|
14,638 | (7,431 | ) | |||||
Total
|
$ | 4,052 | $ | 733 |
|
·
|
Long-term debt, and
|
|
·
|
Operating leases for office facilities
|
Payments due in twelve month periods ending:
|
||||||||||||||||||||
Contractual Obligations
|
Total
|
June 30,
2012
|
June 30,
2013-2014
|
June 30,
2015-2016
|
Thereafter
|
|||||||||||||||
Long-term debt (1)
|
$ | 95,017 | $ | 157 | $ | 348 | $ | 94,512 | $ | — | ||||||||||
Interest on long-term debt (2)
|
11,741 | 2,961 | 5,890 | 2,890 | — | |||||||||||||||
Lease obligations (3)
|
119 | 46 | 73 | — | — | |||||||||||||||
Total
|
$ | 106,877 | $ | 3,164 | $ | 6,311 | $ | 97,402 | $ | — |
|
(1)
|
These amounts represent the balances outstanding under our credit facility and the real estate lien note. These repayments assume that we will not borrow additional funds.
|
|
(2)
|
Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.
|
|
(3)
|
Lease on office space in Calgary, Alberta, which expires on January 30, 2014.
|
June 30, 2011
|
December 31, 2010
|
|||||||
Credit facility
|
$ | 90,000 | $ | 136,000 | ||||
Real estate lien note
|
5,017 | 5,092 | ||||||
95,017 | 141,092 | |||||||
Less current maturities
|
(157 | ) | (152 | ) | ||||
$ | 94,860 | $ | 140,940 |
Fixed-Price Swaps
|
||||||||||||||||
Oil
|
Gas
|
|||||||||||||||
Contract Period
|
Daily
Volume
(Bbl)
|
Swap
Price
(per Bbl)
|
Daily
Volume
(MMBtu)
|
Swap
Price
(per MMBtu)
|
||||||||||||
2011
|
1,035 | $ | 76.61 | 9,580 | $ | 6.52 | ||||||||||
2012
|
946 | $ | 70.89 | 8,303 | $ | 6.77 | ||||||||||
2013
|
705 | $ | 80.79 | 5,962 | $ | 6.84 |
Derivative Instrument Sensitivity
|
Fixed-Price Swaps
|
||||||||||||||||
Oil
|
Gas
|
|||||||||||||||
Contract Period
|
Daily
Volume
(Bbl)
|
Swap
Price
(per Bbl)
|
Daily
Volume
(MMBtu)
|
Swap
Price
(per MMBtu)
|
||||||||||||
2011
|
1,035 | $ | 76.61 | 9,580 | $ | 6.52 | ||||||||||
2012
|
946 | $ | 70.89 | 8,303 | $ | 6.77 | ||||||||||
2013
|
705 | $ | 80.79 | 5,962 | $ | 6.84 |
|
(a)
|
Exhibits
|
|
Exhibit 31.1
|
Certification - Robert L.G. Watson, CEO
|
|
Exhibit 31.2
|
Certification – Chris E. Williford, CFO
|
|
Exhibit 32.1
|
Certification pursuant to 18 U.S.C. Section 1350 – Robert L.G. Watson, CEO
|
|
Exhibit 32.2
|
Certification pursuant to 18 U.S.C. Section 1350 – Chris E. Williford, CFO
|
Date: August 9, 2011
|
By: /s/Robert L.G. Watson
|
||
ROBERT L.G. WATSON,
|
|||
President and Chief
|
|||
Executive Officer
|
Date: August 9, 2011
|
By: /s/Chris E, Williford
|
||
CHRIS E. WILLIFORD,
|
|||
Executive Vice President and
|
|||
Principal Accounting Officer
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Abraxas Petroleum Corporation;
|
|
2.
|
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
|
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
|
(a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
|
|
(b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
|
(c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
|
(d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
|
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
all significant deficiencies in the design or operation of internal controls which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
(b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Abraxas Petroleum Corporation;
|
|
2.
|
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
|
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
|
(a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
|
|
(b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
|
(c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
|
(d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
|
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
all significant deficiencies in the design or operation of internal controls which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
(b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Act of 1934; and
|
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Act of 1934; and
|
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Condensed Consolidated Balance Sheets (Parenthetical) (Unaudited) (USD $)
|
Dec. 31, 2010
|
Jun. 30, 2010
|
---|---|---|
Stockholder's Equity: | Â | Â |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock ,authorized shares (in shares) | 1,000,000 | 1,000,000 |
Preferred stock, issued shares (in shares) | 0 | 0 |
Preferred stock, Outstanding shares (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, authorized shares (in shares) | 200,000,000 | 200,000,000 |
Preferred stock, issued shares (in shares) | 91,740,465 | 91,740,465 |
Preferred stock ,outstanding shares (in shares) | 76,427,561 | 76,427,561 |
Condensed Consolidated Statements of Operations (Unaudited) (USD $)
In Thousands, except Per Share data |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Revenue: | Â | Â | Â | Â |
Oil and gas production revenues | $ 16,653 | $ 14,646 | $ 30,500 | $ 30,509 |
Rig revenues | 297 | 259 | 492 | 520 |
Other | 3 | 4 | 4 | 6 |
Total revenues | 16,953 | 14,909 | 30,996 | 31,035 |
Operating costs and expenses: | Â | Â | Â | Â |
Lease operating expenses | 5,601 | 5,040 | 9,622 | 9,627 |
Production taxes | 1,426 | 1,525 | 2,680 | 3,227 |
Depreciation, depletion, and amortization | 3,780 | 4,433 | 7,210 | 8,674 |
Rig operations | 262 | 193 | 451 | 390 |
General and administrative (including stock-based compensation of $706, $537, $1,069, and $847) | 2,446 | 2,191 | 5,092 | 4,332 |
Operating expenses | 13,515 | 13,382 | 25,055 | 26,250 |
Operating income | 3,438 | 1,527 | 5,941 | 4,785 |
Other (income) expense: | Â | Â | Â | Â |
Interest income | (2) | (2) | (4) | (4) |
Interest expense | 1,336 | 2,252 | 2,941 | 4,586 |
Amortization of deferred financing fee | 770 | 513 | 1,270 | 1,322 |
(Gain) loss on derivative contracts (unrealized $(7,959), $(5,941), $3,019 and $(17,636)) | (6,846) | (6,550) | 4,247 | (17,527) |
Equity in (income) loss of joint venture | (769) | 0 | (1,518) | 0 |
Other | 12 | 14 | 87 | (75) |
Total other (income) expense | (5,499) | (3,773) | 7,023 | (11,698) |
Net income (loss) | $ 8,937 | $ 5,300 | $ (1,082) | $ 16,483 |
Net income (loss) per common share - basic | $ 0.10 | $ 0.07 | $ (0.01) | $ 0.22 |
Net income (loss) per common share - diluted | $ 0.10 | $ 0.07 | $ (0.01) | $ 0.21 |
Document And Entity Information (USD $)
|
6 Months Ended | ||
---|---|---|---|
Jun. 30, 2011
|
May 05, 2011
|
Jun. 30, 2010
|
|
Entity Registrant Name | ABRAXAS PETROLEUM CORP | Â | Â |
Entity Central Index Key | 0000867665 | Â | Â |
Current Fiscal Year End Date | --12-31 | Â | Â |
Entity Well-known Seasoned Issuer | No | Â | Â |
Entity Voluntary Filers | No | Â | Â |
Entity Current Reporting Status | Yes | Â | Â |
Entity Filer Category | Accelerated Filer | Â | Â |
Entity Public Float | Â | Â | $ 191,912,033 |
Entity Common Stock, Shares Outstanding | Â | 91,733,950 | Â |
Document Fiscal Year Focus | 2011 | Â | Â |
Document Fiscal Period Focus | Q2 | Â | Â |
Document Type | 10-Q | Â | Â |
Amendment Flag | false | Â | Â |
Document Period End Date | Jun. 30, 2011 |
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Hedging Activities and Derivatives
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Hedging Activities and Derivatives | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Hedging Activities and Derivatives | Note 6.Hedging Program and Derivatives The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. As a result, our derivative contract transactions do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of our derivative contracts are recognized in earnings during the current period. The following table sets forth our derivative contract position as of June 30, 2011:
At June 30, 2011, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $6.3 million. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% originally was set to expire on August 12, 2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012. The following table illustrates the impact of derivative contracts on the Company's balance sheet:
Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying condensed consolidated statements of operations. |
Formation of Joint Venture
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Jun. 30, 2011
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Formation of Joint Venture | Â | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Formation of Joint Venture | Note 2. Joint Venture On August 18, 2010, Abraxas Petroleum and its wholly-owned subsidiary, Abraxas Operating, LLC, contributed 8,333 net acres in the Eagle Ford Shale play to Blue Eagle Energy, LLC (“Blue Eagle”) and received a $25.0 million equity interest in Blue Eagle pursuant to the terms of the Subscription and Contribution Agreement among Abraxas Petroleum, Abraxas Operating, Blue Eagle and Rock Oil Company, LLC (“Rock Oil”) formerly known as Blue Stone Oil & Gas, LLC. Simultaneously, Rock Oil contributed $25.0 million in cash to Blue Eagle for a $25.0 million equity interest in Blue Eagle. Rock Oil committed to contribute an additional $50.0 million to Blue Eagle and upon full funding, Abraxas Petroleum will own a 25% equity interest in Blue Eagle and Rock Oil will own a 75% equity interest in Blue Eagle. Blue Eagle's subject area encompasses 12 counties across the Eagle Ford Shale play for expected future acreage acquisitions. Abraxas Petroleum operates the wells owned by Blue Eagle and Rock Oil manages the day-to-day business affairs of Blue Eagle. Robert L. G. Watson, our President and CEO, serves as one of the three members of the Board of Managers of Blue Eagle. At formation and through June 29, 2011, we owned a non-controlling 50.0% interest in the joint venture. On June 29, 2011, Rock Oil contributed $11.0 million in cash to Blue Eagle to purchase approximately 2,487 net acres in McMullen County, Texas, which reduced our equity interest to approximately 41.0%. As of June 30, 2011, we owned a non-controlling 41.0% interest in the joint venture. We account for the joint venture under the equity method of accounting. Under the equity method of accounting, Abraxas' share of net income (loss) from the joint venture is reflected as an increase (decrease) in its investment account in “Investment in joint venture” and is also recorded as equity investment income (loss) in “Equity in loss (income) of joint venture.” For the three and six months ended June 30, 2011, we reported a gain of $769,000 and $1.5 million, respectively, related to Blue Eagle. The following table summarizes financial data from Blue Eagle's June 30, 2011 and December 31, 2010 financial statements:
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Business Segments
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Jun. 30, 2011
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Business Segments | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segments | Note 8. Business Segments The following table provides the Company's geographic operating segment data for the three and six months ended June 30, 2011:
The following table provides the Company's geographic asset data as of June 30, 2011 and December 31, 2010:
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Contingencies Litigation
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6 Months Ended |
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Jun. 30, 2011
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Contingencies Litigation [Abstract] | Â |
Contingencies Litigation | Note 9. Contingencies – Litigation From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At June 30, 2011, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its operations. |
Fair Value
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Jun. 30, 2011
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Fair Value | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value | Note 7. Fair Value Fair Value Hierarchy-ASC 820-10 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party's credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables present information about the Company's assets and liabilities measured at fair value as of June 30, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:
The Company has an investment in Insignia Energy Ltd, the surviving entity in the merger with a former subsidiary, consisting of shares of common stock. The stock is actively traded on the Toronto Stock Exchange. This investment is valued at its quoted price as of June 30, 2011 and December 31, 2010 in US dollars. Accordingly, this investment is characterized as Level 1. The Company's derivative contracts consist of NYMEX-based fixed price commodity swaps and interest rate swaps, which are not traded on a public exchange. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity, and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% originally was set to expire on August 12, 2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012. As there is no actively traded market for this type of swap and no observable market parameters, these derivative contracts are classified as Level 3. Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the three and six months ended June 30, 2011 is as follows:
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Income Taxes
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6 Months Ended |
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Jun. 30, 2011
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Income Taxes | Â |
Income Taxes | Note 3. Income Taxes The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. For the three and six months ended June 30, 2011, there were no current or deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowances which have been recorded against such benefits. The Company accounts for uncertain tax positions under provisions ASC 740-10. ASC 740-10 did not have any effect on the Company's financial position or results of operations for the three and six months ended June 30, 2011 and 2010. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2011, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 2000 through 2010 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and Abraxas Energy Partners, L.P., which was merged into a wholly-owned subsidiary of Abraxas in 2009, are currently undergoing an Internal Revenue Service audit on their 2009 Federal income tax returns. |
Long
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Jun. 30, 2011
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Long | Note 4. Long-Term Debt Long-term debt consisted of the following:
Credit Facility On June 30, 2011, we entered into a second amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. As of June 30, 2011, $90.0 million was outstanding under the credit facility. The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. The borrowing base is currently $125.0 million and is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base of $125.0 million was determined based upon our reserve report dated December 31, 2010. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus (b) 1.25-2.25%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus 2.25%-3.25%, depending on the utilization of the borrowing base. At June 30, 2011, the interest rate on the credit facility was 2.94% based on 1-month LIBOR borrowings. Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2015. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders' aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements. Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors' material property and assets. Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter of not less than 2.50 to 1.00. We are also required to maintain a total debt to EBITDAX ratio as of the last day of each quarter of not more than 4.00 to 1.00. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with or at the request of a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20, and any accounts receivable from Blue Eagle and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20, and any accounts payable to Blue Eagle. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts or upon the termination of any hedge contract minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of ASC 815 and ASC 410-20; provided that net income shall be adjusted to negate the effect of non-cash gain or loss attributable to Blue Eagle. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, and obligations with respect to surety bonds and hedge arrangements. We were in compliance with all covenants as of June 30, 2011. As of June 30, 2011, the current ratio was 2.49 to 1.00, the interest coverage ratio was 2.92 to 1.00 and the total debt to EBITDAX ratio was 3.33 to 1.00. In addition to the foregoing and other customary covenants, the credit facility contains a number of covenants that, among other things, restrict our ability to: · incur or guarantee additional indebtedness; · transfer or sell assets; · create liens on assets; · engage in transactions with affiliates other than on an “arm's-length” basis; · make any change in the principal nature of our business; and · permit a change of control. The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. Real Estate Lien Note On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to serve as its corporate headquarters. This note was refinanced in November 2008. The note bears interest at a fixed rate of 6.375%, and is payable in monthly installments of principal and interest of $39,754 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of June 30, 2011, $5.0 million was outstanding on the note. |
Earnings (Loss) Per Share
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Jun. 30, 2011
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Earnings (Loss) Per Share | Â | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings (Loss) Per Share | Note 5. Income (Loss) Per Share The following table sets forth the computation of basic and diluted earnings (loss) per share:
For the six months ended June 30, 2011, none of the shares issuable in connection with stock options or warrants are included in diluted shares. Inclusion of these shares would be antidilutive due to the loss incurred in the period. Had there not been a loss for the period, dilutive shares would have been 2,328 shares for the six months ended June 30, 2011. |
Condensed Consolidated Statements of Operations (Parenthetical) (Unaudited) (USD $)
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Condensed Consolidated Statements of Operations | Â | Â | Â | Â |
General and administrative, stock - based compensation | $ 706 | $ 537 | $ 1,069 | $ 847 |
Loss (gain) on derivative contracts, unrealized | $ (7,959) | $ (5,941) | $ 3,019 | $ (17,636) |
Basis of Presentation
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Jun. 30, 2011
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Basis of Presentation | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Presentation | Note 1. Basis of Presentation The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company's audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission on March 16, 2011. Such policies have been continued without change. Also, refer to the notes to those financial statements for additional details of the Company's financial condition, results of operations, and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim consolidated financial statements have not been audited by our independent registered public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and the cash flows for the periods ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2010. Consolidation Principles The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries, including its wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC. Canadian Abraxas' assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of stockholders' equity. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Stock-based Compensation, Option Plans and Warrants Stock Options The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. For the three and six months ended June 30, 2011, the Company incurred expenses of $599,000 and $866,000, respectively, and for the three and six months ended June 30, 2010, the Company incurred expenses of $444,000 and $637,000, respectively, in stock-based compensation expense related to stock options. The following table summarizes the Company's stock option activity for the six months ended June 30, 2011:
The following table shows the weighted average assumptions used in the Black-Scholes valuation of the fair value of option grants for the six months ended June 30, 2011:
Additional information related to options at June 30, 2011 and December 31, 2010 is as follows:
As of June 30, 2011, there was approximately $3.6 million of unamortized compensation expense related to outstanding options that will be recognized in 2011 through 2015. Restricted Stock Awards Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock was determined using the market price on the grant date and compensation expense is recorded over the applicable vesting periods. The following table summarizes the Company's restricted stock activity for the six months ended June 30, 2011:
For the three and six months ended June 30, 2011, the Company incurred expenses of $107,000 and $203,000, respectively, and for the three and six months ended June 30, 2010, the Company incurred expenses of $93,000 and $210,000, respectively, in stock-based compensation expense related to restricted stock. As of June 30, 2011, there was approximately $455,000 of unamortized compensation expense related to outstanding restricted stock that will be recognized in 2011 through 2015. Warrants On May 25, 2007, the Company entered into a Securities Purchase Agreement with certain accredited investors pursuant to which the Company issued warrants to purchase 1,174,938 shares of common stock. The warrants expire on May 25, 2012 and are exercisable at a price of $3.83 per share, subject to certain adjustments. No warrants were exercised during the six months ended June 30, 2011 or 2010. As of June 30, 2011, there were 878,000 warrants outstanding. Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues as discussed above are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties, except in unusual circumstances. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. The estimates of our reserves as of December 31, 2010 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10% discount rate. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the PV-10 thereof for our oil and gas properties are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for the twelve months ended December 31, 2010. The average realized sales prices used for the estimates were $3.91 per Mcf of gas and $70.72 per Bbl of oil. As of December 31, 2010, the net capitalized costs of our oil and gas properties in the United States did not exceed the present value of our estimated proved reserves; however, the net capitalized costs of our oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $4.8 million, resulting in a write down for the year ended December 31, 2010. As of June 30, 2011, the net capitalized costs of our oil and gas properties in the United States and Canada did not exceed the present value of our estimated proved reserves. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. Restoration, Removal and Environmental Liabilities The Company is subject to extensive Federal, provincial, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable. The Company accounts for asset retirement obligations based on the guidance of Accounting Standards Codification (“ASC”) 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements. The following table summarizes the Company's asset retirement obligation transactions for the six months ended June 30, 2011 and the year ended December 31, 2010:
Working Capital (Deficit) At June 30, 2011, our current liabilities of approximately $33.9 million exceeded our current assets of $22.5 million resulting in a working capital deficit of $11.4 million. This compares to a working capital deficit of approximately $8.9 million at December 31, 2010. Current liabilities at June 30, 2011 primarily consisted of the current portion of derivative liabilities of $11.8 million, trade payables of $13.5 million, revenues due third parties of $6.8 million, and other accrued liabilities of $1.6 million. Recently Issued Accounting Pronouncements In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2010-6, “Improving Disclosures about Fair Value Measurements”. ASU No. 2010-06 amends FASB ASC Topic 820, “Fair Value Measurements and Disclosures,” to require additional information to be disclosed principally regarding Level 3 measurements and transfers to and from Level 1 and 2. In addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 measurements. This guidance is generally effective for interim and annual reporting periods beginning after December 15, 2009; however, requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). This update did not have a material impact on the Company's consolidated financial statements. In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU will require companies to present the components of net and comprehensive income in either one or two consecutive financial statements and eliminates the option to present other comprehensive income in the statement of changes in stockholders' equity. This ASU is effective for fiscal years and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements. In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU expands existing disclosure requirements for fair value measurements and provides additional information on how to measure fair value. The Company is required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements. |
Subsequent Events
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Jun. 30, 2011
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Subsequent Events [Abstract] | Â |
Subsequent Events | Note 10. Subsequent Events On July 5, 2011, the Company purchased a used Oilwell 2000 hp diesel electric drilling rig, which will be refurbished and mobilized to the Williston Basin. The rig is owned by, and will be operated by, Raven Drilling, LLC, a wholly-owned subsidiary of the Company. |