Attached files
file | filename |
---|---|
EX-2.5 - EXHIBIT 2.5 - AMERICAN OIL & GAS INC | c08427exv2w5.htm |
EX-31.2 - EXHIBIT 31.2 - AMERICAN OIL & GAS INC | c08427exv31w2.htm |
EX-32.2 - EXHIBIT 32.2 - AMERICAN OIL & GAS INC | c08427exv32w2.htm |
EX-31.1 - EXHIBIT 31.1 - AMERICAN OIL & GAS INC | c08427exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - AMERICAN OIL & GAS INC | c08427exv32w1.htm |
EX-10.II - EXHIBIT 10(II) - AMERICAN OIL & GAS INC | c08427exv10wii.htm |
Table of Contents
United States Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2010
OR
o | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File No. 1-31900
AMERICAN OIL & GAS INC.
(Exact name of registrant as specified in its charter)
Nevada | 88-0451554 | |
(State or jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
1050 17th Street, Suite 2400, Denver, CO | 80265 | |
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number, including area code (303) 991-0173
Indicate by check mark whether the issuer (i) filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes o No o {Files Not
required}.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer o | Non-accelerated filer o * (*Do not check if a smaller reporting company) |
Smaller reporting company þ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common equity as of
the latest practicable date:
The total shares of $.001 Par Value Common Stock outstanding at November 9, 2010 were
61,029,656.
AMERICAN OIL & GAS INC.
FORM 10-Q
INDEX
FORM 10-Q
INDEX
3 | ||||||||
3 | ||||||||
4 | ||||||||
5 | ||||||||
6 | ||||||||
16 | ||||||||
21 | ||||||||
22 | ||||||||
23 | ||||||||
25 | ||||||||
25 | ||||||||
Exhibit 2.5 | ||||||||
Exhibit 10(ii) | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
2
Table of Contents
PART I
ITEM 1. FINANCIAL STATEMENTS
AMERICAN OIL & GAS INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and cash equivalents |
$ | 13,806,712 | $ | 40,632,284 | ||||
Short-term investments |
1,650,000 | 2,925,000 | ||||||
Accounts receivable |
19,201,075 | 564,533 | ||||||
Well equipment inventory |
1,353,183 | 1,269,774 | ||||||
Prepaid expenses |
131,024 | 149,991 | ||||||
Current deferred tax assets |
114,763 | | ||||||
Total current assets |
36,256,757 | 45,541,582 | ||||||
PROPERTY AND EQUIPMENT, AT COST |
||||||||
Oil and gas properties, full cost method (including unevaluated costs
of $76,347,322 at 9/30/10 and $35,611,363 at 12/31/09) |
122,422,388 | 44,454,942 | ||||||
Other property and equipment |
449,270 | 406,273 | ||||||
Total property and equipment |
122,871,658 | 44,861,215 | ||||||
Less-accumulated depreciation, depletion and amortization |
(8,382,557 | ) | (5,771,547 | ) | ||||
Net property and equipment |
114,489,101 | 39,089,668 | ||||||
OTHER ASSETS |
||||||||
Drilling prepayments |
269,020 | | ||||||
Intangible asset, net of accumulated amortization |
| 60,000 | ||||||
Other |
130,752 | 80,652 | ||||||
$ | 151,145,630 | $ | 84,771,902 | |||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
CURRENT LIABILITIES |
||||||||
Accounts payable and accrued liabilities |
$ | 18,369,405 | $ | 1,032,248 | ||||
Income taxes payable |
| | ||||||
Total current liabilities |
18,369,405 | 1,032,248 | ||||||
LONG-TERM LIABILITIES |
||||||||
Asset retirement obligations |
225,099 | 436,487 | ||||||
Deferred income taxes |
6,239,763 | | ||||||
Total long-term liabilities |
6,464,862 | 436,487 | ||||||
COMMITMENTS AND CONTINGENCIES (Note 14) |
||||||||
STOCKHOLDERS EQUITY |
||||||||
Preferred stock, $.001 par value, authorized 24,100,000 shares; no
outstanding shares at 09/30/10 and 12/31/09 |
| | ||||||
Common stock, $.001 par value, authorized 100,000,000 shares; issued and
outstanding 61,029,656 shares at 9/30/10, 57,472,399 shares at 12/31/09 |
61,030 | 57,472 | ||||||
Additional paid-in capital |
137,685,912 | 122,267,594 | ||||||
Accumulated deficit |
(11,435,579 | ) | (39,096,899 | ) | ||||
Accumulated other comprehensive income |
| 75,000 | ||||||
Total equity |
126,311,363 | 83,303,167 | ||||||
$ | 151,145,630 | $ | 84,771,902 | |||||
The accompanying notes are an integral part of the condensed consolidated financial statements.
3
Table of Contents
AMERICAN OIL & GAS INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATION
(UNAUDITED)
Three months ended | Nine months ended | |||||||||||||||
September 30 | September 30 | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
REVENUES: |
||||||||||||||||
Oil and gas sales |
$ | 4,806,383 | $ | 462,553 | $ | 8,083,918 | $ | 1,285,705 | ||||||||
OPERATING EXPENSES: |
||||||||||||||||
Lease operating |
912,493 | 278,429 | 1,777,764 | 848,354 | ||||||||||||
General and administrative |
2,804,686 | 1,198,188 | 6,168,688 | 4,242,539 | ||||||||||||
Depletion, depreciation and amortization |
1,621,413 | 276,417 | 2,671,011 | 738,732 | ||||||||||||
Impairment of oil & gas properties |
| 1,850,000 | | 3,950,000 | ||||||||||||
Impairment of well equipment inventory |
26,571 | 409,852 | 200,356 | 565,991 | ||||||||||||
Accretion of asset retirement obligation |
3,741 | 9,837 | 16,849 | 30,057 | ||||||||||||
5,368,904 | 4,022,723 | 10,834,668 | 10,375,673 | |||||||||||||
GAIN ON SALE OF OIL & GAS PROPERTIES |
| | 36,400,000 | | ||||||||||||
INCOME (LOSS) FROM OPERATIONS |
(562,521 | ) | (3,560,170 | ) | 33,649,250 | (9,089,968 | ) | |||||||||
OTHER INCOME (LOSS): |
||||||||||||||||
Investment income |
38,255 | 9,632 | 137,070 | 47,949 | ||||||||||||
INCOME (LOSS) BEFORE INCOME TAXES |
(524,266 | ) | (3,550,538 | ) | 33,786,320 | (9,042,019 | ) | |||||||||
Income tax provision (benefit) -current |
(200,000 | ) | (149,965 | ) | | (149,965 | ) | |||||||||
Income tax provision (benefit) -deferred |
(205,000 | ) | | 6,125,000 | | |||||||||||
NET INCOME (LOSS) |
$ | (119,266 | ) | $ | (3,400,573 | ) | $ | 27,661,320 | $ | (8,892,054 | ) | |||||
NET INCOME (LOSS) PER SHARE: |
||||||||||||||||
Basic |
$ | (0.00 | ) | $ | (0.07 | ) | $ | 0.46 | $ | (0.18 | ) | |||||
Diluted |
$ | (0.00 | ) | $ | (0.07 | ) | $ | 0.45 | $ | (0.18 | ) | |||||
Weighted average common shares outstanding: |
||||||||||||||||
Basic |
61,029,384 | 48,307,399 | 59,790,245 | 48,284,846 | ||||||||||||
Diluted |
61,029,384 | 48,307,399 | 61,108,977 | 48,284,846 |
The accompanying notes are an integral part of the condensed consolidated financial statements.
4
Table of Contents
AMERICAN OIL & GAS INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine months ended | ||||||||
September 30 | ||||||||
2010 | 2009 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net income (loss) |
$ | 27,661,320 | $ | (8,892,054 | ) | |||
Adjustments to reconcile net income (loss) to
net cash from operating activities: |
||||||||
Gain on sale of oil and gas assets |
(36,400,000 | ) | | |||||
Deferred income taxes |
6,125,000 | | ||||||
Depletion, depreciation and amortization |
2,671,011 | 738,732 | ||||||
Share-based compensation expenses |
808,977 | 823,130 | ||||||
Impairment of oil and gas properties |
| 3,950,000 | ||||||
Impairment of well equipment inventory |
200,356 | 565,991 | ||||||
Accretion of asset retirement obligations |
16,849 | 30,057 | ||||||
Changes in assets and liabilities: |
||||||||
Decrease (increase) in receivables |
(4,513,769 | ) | 271,629 | |||||
Decrease (increase) in prepaid expenses |
18,967 | 87,080 | ||||||
Decrease (increase) in well equipment inventory |
(283,765 | ) | (676,696 | ) | ||||
Increase (decrease) in accounts payable and accrued liabilities |
999,936 | 45,057 | ||||||
Net cash used in operating activities |
(2,695,118 | ) | (3,057,074 | ) | ||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Cash proceeds from sale of oil and gas properties |
47,774,112 | | ||||||
Cash paid for oil and gas property acquisition, exploration & development |
(73,546,599 | ) | (9,728,311 | ) | ||||
Drilling prepayments |
(269,020 | ) | ||||||
Proceeds from redemptions and sales of short-term investments |
1,200,000 | 2,600,000 | ||||||
Cash paid for office equipment |
(42,997 | ) | (36,464 | ) | ||||
Cash paid for other long-term assets |
(50,100 | ) | (50,100 | ) | ||||
Net cash used in investing activities |
(24,934,604 | ) | (7,214,875 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Stock option exercises |
716,650 | | ||||||
Stock warrant exercise |
87,500 | | ||||||
Net cash provided by financing activities |
804,150 | | ||||||
NET DECREASE IN CASH |
(26,825,572 | ) | (10,271,949 | ) | ||||
CASH, BEGINNING OF PERIODS |
40,632,284 | 23,269,725 | ||||||
CASH, END OF PERIODS |
$ | 13,806,712 | $ | 12,997,776 | ||||
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION |
||||||||
Cash paid for interest |
$ | | $ | | ||||
Cash paid for income taxes |
$ | | $ | 130,000 | ||||
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING
AND FINANCING ACTIVITIES |
||||||||
Oil and gas properties acquired for stock |
$ | 13,804,000 | $ | | ||||
Exchange of oil and gas properties |
$ | | $ | 420,000 | ||||
Net increase in payables for capital expenditures |
$ | 16,337,221 | $ | | ||||
Net increase in receivables for capital expenditures |
$ | 15,908,110 | $ | |
The accompanying notes are an integral part of the condensed consolidated financial statements.
5
Table of Contents
AMERICAN OIL & GAS INC.
Notes to Condensed Consolidated Financial Statements
(UNAUDITED)
September 30, 2010
NOTE 1 COMPANY AND BUSINESS
In these Notes, the terms Company, American, we, us, our and terms of similar import
refer to American Oil & Gas Inc.
We are an independent energy company engaged in the exploration, development, acquisition and
sale of crude oil and natural gas reserves and production in the western United States. Our
operations are currently focused in North Dakota. We own a wholly-owned subsidiary, Tower American
Corporation, for conducting oil and gas exploration and production operations in Colorado. We do
not anticipate operating outside the United States. Our fiscal year end is December 31.
NOTE 2 BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
We have prepared the accompanying unaudited condensed balance sheet as of December 31, 2009
(which has been derived from audited financial statements) and the accompanying unaudited interim
condensed financial statements pursuant to the rules and regulations of the Securities and Exchange
Commission (SEC). Certain information and footnote disclosure normally included in financial
statements prepared in accordance with generally accepted accounting principles (GAAP) have been
condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are
adequate to make the information not misleading and recommend that these condensed financial
statements be read in conjunction with our audited financial statements and notes included in our
amended Annual Report on Form 10-K for the year ended December 31, 2009.
References to GAAP issued by the Financial Accounting Standards Board (FASB) in these
footnotes are to the FASB Accounting Standards Codification, sometimes referred to as
the Codification or ASC.
In the opinion of management, the interim data includes all adjustments, consisting only of
normal recurring adjustments, necessary for a fair presentation of the results for the interim
period. The results of operations for the nine-month period ended September 30, 2010 are not
necessarily indicative of the operating results for the entire year ending December 31, 2010.
USE OF ESTIMATES As further discussed on pages F-7 and F-8 of our amended Annual Report on
Form 10-K for the year ended December 31, 2009, the preparation of financial statements in
conformity with generally accepted accounting principles requires us to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those estimates.
SIGNIFICANT ACCOUNTING POLICIES For descriptions of the Companys significant accounting
policies, please see pages F-8 through F-11 of our amended Annual Report on Form 10-K for the year
ended December 31, 2009.
For interim financial reporting during a fiscal year, current and deferred tax provisions are
based on projected effective tax rates for the full year applied to the pre-tax income for the
interim period, whereby the deferred tax assets and liabilities at the end of an interim period are
impacted by their projected balances for the year-end.
Amortization of oil and gas property costs is computed quarterly and not year-to-date, using
the estimated proved reserves as of the end of the calendar quarter. Amortization for the fiscal
year is the sum of the four quarterly amortization amounts. Management estimated the proved
reserves at September 30, 2010 and September 30, 2009, with consideration of (1) the proved reserve
estimates for the prior fiscal year-end prepared by
independent engineering consultants and (2) significant new discoveries and significant
changes during the interim period in production, ownership, and other factors underlying reserve
estimates.
6
Table of Contents
RECENT ACCOUNTING PRONOUNCEMENTS As of September 30, 2010, there have been no recent
accounting pronouncements currently relevant to the Company in addition to those discussed on page
F-12 of our amended Annual Report on Form 10-K for the year ended December 31, 2009.
GAS BALANCING As of September 30, 2010 and December 31, 2009, our gas production was in
balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have
an interest equaled our entitled interest in gas production from those wells.
INVENTORY Inventories classified as current assets consists of purchased well casing and
tubing stored in central third-party yards serving multiple oil and gas companies. Such inventory
is carried at the lower of cost or market using weighted average cost. Casing and tubing moved to
well sites are classified as non-current assets to be used in the completion of wells.
RECLASSIFICATION Certain amounts in the 2009 consolidated financial statements have been
reclassified to conform to the 2010 financial statement presentation. Such reclassifications have
had no effect on net loss for the period in 2009.
ASSET RETIREMENT OBLIGATIONS Our asset retirement obligations (ARO) relate primarily to
the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas
properties. The following table reflects the change in ARO for the three-month and nine-month
periods ended September 30, 2010 and September 30, 2009:
Three months ended | Nine months ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Beginning asset retirement obligation |
$ | 151,309 | $ | 492,115 | $ | 436,488 | $ | 430,686 | ||||||||
Liabilities incurred |
73,791 | 142 | 125,009 | 53,509 | ||||||||||||
Liabilities settled |
| (79,432 | ) | (341,709 | ) | (79,432 | ) | |||||||||
Revisions in estimated liabilities |
(3,742 | ) | (10,830 | ) | (11,538 | ) | (22,988 | ) | ||||||||
Accretion |
3,741 | 9,837 | 16,849 | 30,057 | ||||||||||||
Ending asset retirement obligation |
$ | 225,099 | $ | 411,832 | 225,099 | $ | 411,832 | |||||||||
Current portion of obligation, end of period |
$ | | $ | | $ | | $ | |
NET INCOME (LOSS) PER SHARE Basic net income (loss) per share is computed by dividing net
income (loss) attributable to common stockholders by the weighted number of common shares
outstanding during the period. Diluted net income (loss) per share reflects per share amounts that
would have resulted if dilutive potential common stock had been converted to common stock.
7
Table of Contents
NOTE 3 PROPERTY AND EQUIPMENT
Property and equipment at September 30, 2010 and December 31, 2009, consisted of the
following:
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Oil and gas properties, full cost method |
||||||||
Unevaluated costs, not yet subject to amortization |
$ | 76,347,322 | $ | 35,611,363 | ||||
Evaluated costs |
46,075,066 | 8,843,579 | ||||||
122,422,388 | 44,454,942 | |||||||
Less accumulated amortization |
(8,061,016 | ) | (5,510,016 | ) | ||||
Net carrying value of oil and gas properties |
114,361,372 | 38,944,926 | ||||||
Cost of other property and equipment |
449,270 | 406,273 | ||||||
Less accumulated depreciation and amortization |
(321,541 | ) | (261,531 | ) | ||||
Net property and equipment |
$ | 114,489,101 | $ | 39,089,668 | ||||
Our primary focus area is our Goliath Bakken and Three Forks focused project located in the
Williston Basin, North Dakota where we control at September 30, 2010, approximately 85,000 net
acres.
At September 30, 2010, we were evaluating the productive potential of another area located in
the Rocky Mountain region that we call our Bigfoot project. This is a shallow natural gas project
where we currently control approximately 213,000 gross (131,000 net) acres. We are primarily
targeting a formation that is less that 2,000 deep and have drilled test wells for less than
$100,000 per well.
Sales of Oil & Gas Properties
On March 31, 2010, American and North Finn LLC (North Finn) sold substantially all their
ownership in wells and undeveloped acreage in three Wyoming counties, including Americans
ownership interests in the Fetter and Krejci projects. For the properties sold, American received
$46,181,289 in cash on March 31, 2010 from the buyer, Chesapeake AEZ Exploration L.L.C.
(Chesapeake).
On June 29, 2010, American sold to Chesapeake for $1,592,823 Americans remaining rights in
oil and gas leases in those three counties after American was able to demonstrate having
satisfactory title to the lease rights sold in June. The $1,592,823 in sales proceeds were
received on July 7, 2010.
Under the full cost accounting method, we recognized at March 31, 2010 a $36,400,000 gain on
the March 31st sale, by allocating cost to the properties sold based on their relative
total fair value to the estimated fair value of the full cost pool immediately preceding the sale.
Under the full cost accounting method, gain on property sales is not recognized unless
non-recognition of such gain or loss would significantly alter the relationship between capitalized
costs and proved oil and gas reserves of the cost center. Non-recognition of the $36,400,000 gain
would have reduced the amortization base at March 31, 2010 to zero, significantly altering the
relationship, whereby non-recognition was not allowed under full cost accounting. Since the
properties sold were significantly different from the properties retained with regard to the nature
and extent of proved reserves and property economics, then under the full cost accounting method,
the sales gain at March 31, 2010 was based on allocating a portion of the US cost centers
capitalized costs to the properties sold based on the relative total fair value of the properties
sold to the estimated total fair value of the US cost centers properties immediately preceding the
sale.
The gain on the sale of properties in June 2010 was not recognized because non-recognition
would not significantly alter the relationship between capitalized costs and proved oil and gas
reserves of the cost center.
Unevaluated Oil and Gas Properties
Our $76,347,322 of capitalized unevaluated costs at September 30, 2010, substantially
consisted of (i) approximately $53 million for lease rights at our Goliath Project, (ii) nearly $15
million for wells-in-progress at our
Goliath Project in North Dakota, (iii) approximately $4 million in Bigfoot undeveloped acreage
and (iv) approximately $1 million in costs of wells drilled or in progress, but not yet evaluated
at Bigfoot. Included in capital additions for the nine-month period ended September 30, 2010 were
$0.7 million of internal land department and geologist costs directly associated with the
acquisition, exploration and development of oil and gas properties.
8
Table of Contents
Ceiling Impairment
We use the full-cost accounting method, which requires recognition of an impairment of oil and
gas properties when the total capitalized costs (net of related deferred income taxes) exceed a
ceiling as described on page F-9 of our amended Annual Report on Form 10-K as of December 31,
2009. We had no ceiling impairment for the nine-month period ended September 30, 2010, but we
recognized a $3,950,000 impairment for the nine-month period ended September 30, 2009.
The following table shows Depreciation, Depletion and Amortization (DD&A) expense by type of
asset:
Nine-month Period | ||||||||
Ended September 30, | ||||||||
2010 | 2009 | |||||||
Amortization of costs for evaluated oil and gas properties |
$ | 2,551,000 | $ | 546,000 | ||||
Amortization of Intangible Asset |
60,000 | 135,000 | ||||||
Depreciation of office equipment, furniture and software |
60,011 | 57,732 | ||||||
Total DD&A expense |
$ | 2,671,011 | $ | 738,732 | ||||
NOTE 4 SIGNIFICANT CHANGES IN PROVED RESERVE ESTIMATES
Our proved reserves at September 30, 2010, were estimated internally by management. The
estimates are significantly greater than at December 31, 2009, as shown in the following table:
Oil (bbls) | Gas (mcf) | |||||||
Proved reserves at December 31, 2009 |
147,510 | 956,550 | ||||||
Less proved reserves of properties sold 3/31/10 |
(22,957 | ) | (392,601 | ) | ||||
Less production for nine months ended 9/30/10 |
(119,374 | ) | (68,324 | ) | ||||
Proved reserve additions, nine months ended 9/30/10 |
1,815,264 | 2,891,687 | ||||||
Net revisions |
155,733 | (143,937 | ) | |||||
Proved reserves at September 30, 2010 |
1,976,176 | 3,243,375 | ||||||
Percentage net change in proved reserves |
1,240 | % | 239 | % |
Proved reserve additions relate primarily to our interests in thirteen North Dakota wells and
four proved undeveloped locations in our Goliath Project.
The standardized measure of discounted future net cash flows relating to proved oil and gas
reserves increased from approximately $2.5 million at December 31, 2009, to approximately $38
million at September 30, 2010.
NOTE 5 SHORT-TERM INVESTMENTS
Our short-term investments of $1,650,000 at September 30, 2010, and $2,925,000 at December 31,
2009, were comprised of auction-rate preferred shares (ARPS) issued by closed-end mutual funds.
ARPS are a form of auction-rate securities (ARS) that were bought and sold at par value prior to
March 2008 at special auctions held every 7 days or 28 days and paying variable-rate dividends,
with the rate re-determined at the auctions. By March 2009, there were no parties willing to buy
ARPS at par value at the auctions, i.e., the auction system collapsed. The ARPS are preferred
shares with no maturity date and with no right for the holder to put the securities to the ARPS
issuer (the closed-end mutual fund) for redemption. Since March 2008, many issuers of ARPS have
redeemed some or all of their ARPS at par value, and several large investment banks and brokerage
firms (generally in settlement with customers or with government agencies) have bought back their
customers ARPS at par value.
9
Table of Contents
The ARPS total par value and carrying value (estimated fair value) since December 31, 2009,
through September 30, 2010, are summarized in the following table:
Carrying | ||||||||
Par Value | Value | |||||||
As of December 31, 2009 |
$ | 3,150,000 | $ | 2,925,000 | ||||
Increase in estimated fair value |
n/a | 25,000 | ||||||
As of March 31, 2010 |
3,150,000 | 2,950,000 | ||||||
Less redemption in May 2010 |
(1,200,000 | ) | (1,200,000 | ) | ||||
Decrease in estimated fair value at 9/30/10 |
n/a | (100,000 | ) | |||||
As of September 30, 2010 |
$ | 1,950,000 | $ | 1,650,000 | ||||
On August 6, 2009, American filed with the Financial Industry Regulatory Authority (FINRA) a
statement of claim against Jefferies & Company, Inc. (Jefferies), as Americans broker with
regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at
par value Americans remaining unredeemed ARPS, (ii) reimburse American for consequential damages
(approximating $150,000 to date) and for Americans legal costs in the arbitration and (iii) pay
American interest at 8% per annum under Colorado statute C. R. S. § 5-12-102, less the ARPS
dividends American received following the failed auctions. The arbitration hearing is scheduled
to take place in June 2011.
We expect to have our ARPS entirely liquidated for cash before September 30, 2011. Absent
full liquidation at par value, we expect to sell any remaining ARPS in the secondary market at
expected losses (including significant transaction costs) approximating 10% to 20% of the par value
of ARPS sold. We may receive an award in arbitration with Jefferies; however, we have no
assurance that we will be successful in our claim against Jefferies.
The ARPS we own at September 30, 2010 are classified as short-term investments held for sale.
Unrealized gains and temporary unrealized losses are recorded in Other Comprehensive Income (Loss).
Unrealized losses that are other-than-temporary are reflected in the consolidated statement of
operations. Unrealized gains resulting from increases in fair value are recorded in Other
Comprehensive Income.
At September 30, 2010, the ARPS $1,950,000 total par value exceeded their $1,650,000 total
carrying value (i.e., estimated fair value) by $300,000. The $300,000 net loss was recognized in
2008. Fair value, by definition, is before transaction costs in selling the ARPS (See Note 6).
The ARPS dividend rates approximated 0.8% per annum at September 30, 2010. Dividend rates
fluctuate weekly or monthly generally at a small premium over 30-day LIBOR or over short-term AA
commercial paper.
NOTE 6 FAIR VALUE MEASUREMENTS
Effective January 1, 2008, we adopted ASC 820 Fair Value Measurements and Disclosures for all
financial assets and liabilities measured at fair value on a recurring basis. We chose not to
elect the fair value option as prescribed by ASC 820 for financial assets and liabilities that had
not been previously carried at fair value. Therefore, material financial assets and liabilities not
carried at fair value, such as trade accounts receivable and accounts payable, are still reported
at their face values.
ASC 820 defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement
date. ASC 820 establishes market or observable inputs as the preferred sources of fair values,
followed by assumptions based on hypothetical transactions in the absence of market inputs. The
statement calls for disclosures grouping these financial assets and liabilities, based on the
following levels of significant inputs to measuring fair value:
| Level 1 Quoted prices in active markets for identical assets or liabilities |
||
| Level 2 Quoted prices in active markets for similar assets and liabilities, quoted
prices for identical or similar instruments in markets that are not active, and
model-derived valuations whose inputs are observable or whose significant value drivers
are observable |
||
| Level 3 Significant inputs to the valuation model which are unobservable. |
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The following table presents information about the Companys assets and liabilities measured
at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. The table shows
the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair
values.
Level 1 | Level 2 | Level 3 | ||||||||||||||
Total | inputs | inputs | inputs | |||||||||||||
As of December 31, 2009 |
||||||||||||||||
Assets: |
||||||||||||||||
Short-term investments available for sale: |
||||||||||||||||
Auction Rate Preferred Shares (ARPS) |
$ | 2,925,000 | $ | | $ | | $ | 2,925,000 | ||||||||
Liabilities |
$ | | $ | | $ | | $ | | ||||||||
As of September 30, 2010 |
||||||||||||||||
Assets: |
||||||||||||||||
Short-term investments available for sale: |
||||||||||||||||
Auction Rate Preferred Shares (ARPS) |
$ | 1,650,000 | $ | | $ | | $ | 1,650,000 | ||||||||
Liabilities |
$ | | $ | | $ | | $ | |
Our claim against Jefferies (see Note 5) is not reflected in estimation as to the fair value
of our ARPS, because fair value is based on what a third party would be willing to pay for the
securities excluding any legal rights at September 30, 2010 that American may have against
Jefferies.
The risk of loss associated with credit risk is negligible because credit rating agencies
continue to classify such ARPS as Triple-A credit risks. Federal law requires the closed-end
mutual fund that issued the ARPS to maintain asset values of no less than 200% of the ARPS par
value and accrued dividends. A decline in asset value below the 200% ratio requires the fund to
quickly restore the ratio such as by selling some assets and using the sale proceeds to pay accrued
dividends and buy back a portion of the ARPS at par value. The closed-end mutual funds that issued
the ARPS we hold have substantially all of their assets in a variety of corporate bonds and/or
stock, which facilitates the selling of assets to redeem sufficient ARPS to maintain the required
200% coverage ratio.
The methodology for Level 3 valuation at September 30, 2010 was similar to that at December 31,
2009 described on page F-18 of our amended Annual Report on Form 10-K as of December 31, 2009.
NOTE 7 INCOME TAXES
We account for income taxes under the provisions of ASC Topic 740, Income Taxes, which
provides for an asset and liability approach in accounting for income taxes. Under this approach,
deferred tax assets and liabilities are recognized based on anticipated future tax consequences,
using currently enacted tax laws, attributable to temporary differences between the carrying
amounts of assets and liabilities for financial reporting purposes and the amounts calculated for
income tax purposes.
At September 30, 2010, we expect to owe no alternative minimum tax for 2010 and we have
reversed the $200,000 estimated alternative minimum tax recorded at March 31, 2010. For the
nine-month period ended September 30, 2010, we recognized a $0 current tax provision and a
$6,125,000 deferred income tax provision, net of a $7 million reversal of the deferred tax asset
valuation allowance. We currently estimate that our effective income tax rate for the year ending
December 31, 2010 will approximate 18% (and 39% excluding the effect of the reversal of the
deferred tax asset valuation allowance).
We file annual US federal income tax returns and have filed annual income tax returns for the
states of Colorado, Montana, North Dakota and Utah. We have done business in Wyoming, but Wyoming
does not impose corporate income taxes. We believe that as of November 12, 2010, we are no longer
subject to income tax examinations by tax authorities for years before 2006 for Colorado and before
2007 for federal, Montana, North Dakota and Utah income tax returns. Income taxing authorities
have conducted no formal examinations of our past federal and state income tax returns and
supporting records, except for an IRS examination for the year 2007. The
IRS examination began in October 2010 and is still in process. We do not expect the
examination to result in any assessments of taxes, penalties or interest.
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In March and April 2009, the Utah State Tax Commission conducted a limited review of our
franchise tax returns for 2005, 2006 and 2007, but the review did not become a formal examination
or audit, and the Commission issued no notice of any taxes, penalties or interest due.
On January 1, 2007, we adopted the provisions of ASC Topic 740 regarding uncertainty in income
taxes. We found no significant uncertain tax positions as of any date as of September 30, 2010.
Our policy is to recognize interest related to unrecognized tax benefits in interest expense
and to recognize tax penalties in operating expense. However, given our substantial net operating
loss carryforwards, we do not anticipate any significant interest expense or penalties charged for
any examining agents tax adjustments of returns prior to 2010.
NOTE 8 EQUITY
Common Stock
The following transactions occurred during the nine-month period ended September 30, 2010 with
regard to our common stock:
| On January 26, 2010, we issued to each of our three independent directors 7,519 shares
of common stock. |
| In February 2010, our Vice-President of Land earned on the third anniversary of his
employment 4,000 shares of our common stock. |
| During the quarter ended March 31, 2010, a Director exercised his option, buying 12,500
shares of our common stock, at a $2.38 exercise price per share. |
| During the quarter ended March 31, 2010, our CFO exercised his option, buying 68,000
shares of our common stock, at an exercise price of $2.00 per share. |
| During the quarter ended March 31, 2010, four non-officer employees exercised options to
purchase a total of 121,400 shares of our common stock, at an exercise price of $2.00 per
share. |
| During the quarter ended June 30, 2010, three option holders exercised stock options,
buying a total of 213,800 shares at a total exercise cost of $312,850. |
| During the quarter ended September 30, 2010, an independent contractor exercised his
warrant to purchase 25,000 shares of our common stock at an exercise price of $3.50 per
share. |
| For the quarter ended March 31, 2010, Additional Paid-In Capital increased by $315,499
for recognition of share-based compensation consisting of (i) $174,762 in share-based
compensation related to stock options, (ii) $50,734 related to accruals for granted stock
vesting after grant and (iii) $90,003 relating to stock granted to directors with limited
vesting restrictions. |
| For the quarter ended June 30, 2010, Additional Paid-In Capital increased by $258,914
for recognition of share-based compensation consisting of (i) $170,780 in share-based
compensation related to stock options, and (ii) $88,134 related to accruals for granted
stock vesting after grant. |
| For the quarter ended September 30, 2010, Additional Paid-In Capital increased by
$234,565 for recognition of share-based compensation consisting of (i) $117,631 in
share-based compensation related to stock options and warrants, and (ii) $116,934 related
to accruals for granted stock vesting after grant. |
| On July 1, 2010, we issued and held in escrow a total of 110,000 restricted, unvested
shares of common stock granted in April 2010 among all employees except for four employees
who were either directors or owned more than 500,000 shares of Company common stock. |
| On July 1, 2010, we issued and held in escrow 80,000 restricted unvested shares of
common stock granted on May 28, 2001 to a petroleum engineer hired to serve as our
Completions and Production Manager for our Goliath Project. |
| Effective March 31, 2010 with the closing of the sale of certain Powder River Basin oil
and gas properties, we increased Additional Paid-In Capital by $13,804,000 in recognition
of the sale fulfilling all obligations of North Finn LLC for its right to receive 2,900,000
restricted shares of our common stock. In May 2010, North Finn LLC formally exercised its
option and received the 2,900,000 shares. |
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Warrants
On April 6, 2010, we granted warrants to two consultants, each for 25,000 shares, vesting on
April 6, 2011 (or upon an earlier change in control) and expiring on April 6, 2013, with an
exercise price of $7.25 per share.
At December 31, 2009, we had one outstanding warrant to purchase our common shares. The
warrant was issued April 16, 2008 and was to expire April 16, 2013. It was for 50,000 shares of our
common stock at an exercise price of $3.50 per share. In February 2010, the warrant was
re-issued as two warrants for 25,000 shares each, with the same exercise price per share and the
same expiration date. One of those two warrants was fully exercised in September 2010, whereby
only three of the four warrants were outstanding at September 30, 2010.
Stock Options
In the nine-month period ended September 30, 2010, we granted no stock options and none were
forfeited or expired. As described above, several individuals exercised stock options to acquire a
total of 415,700 shares of our common stock at a total exercise cost of $716,650.
Other Comprehensive Income
During the nine months ended September 30, 2010, Other Comprehensive Income was reduced (from
$75,000) to $0 to reflect a change (net of related deferred income taxes) in the fair value of
short-term investments.
NOTE 9 EARNINGS PER SHARE
The following table summarizes the calculations of basic and diluted net income (loss) per
common share for the three-month and nine-month periods ended September 30, 2010 and September 30,
2009:
Three months ended | Nine months ended | |||||||||||||||
September 30 | September 30 | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net income (loss) |
$ | (119,266 | ) | $ | (3,400,573 | ) | $ | 27,661,320 | $ | (8,892,054 | ) | |||||
Adjustments for dilution |
| | | | ||||||||||||
Net income (loss) adjusted for dilution effects |
$ | (119,266 | ) | $ | (3,400,573 | ) | $ | 27,661,320 | $ | (8,892,054 | ) | |||||
Basic Weighted Average Common Shares |
61,029,384 | 48,307,399 | 59,790,245 | 48,284,846 | ||||||||||||
Add dilutive effects of options and warrants |
| | 1,318,732 | | ||||||||||||
Diluted Weighted Ave. Shares Outstanding |
61,029,384 | 48,307,399 | 61,108,977 | 48,284,846 | ||||||||||||
Net income (loss) per common share, basic |
$ | (0.00 | ) | $ | (0.07 | ) | $ | 0.46 | $ | (0.18 | ) | |||||
Net income (loss) per common share, diluted |
$ | (0.00 | ) | $ | (0.07 | ) | $ | 0.45 | $ | (0.18 | ) |
NOTE 10 PROPOSED MERGER OF AMERICAN INTO HESS SUBSIDIARY
Agreement and Plan of Merger
On July 27, 2010, American entered into an Agreement and Plan of Merger (the Agreement) with
the Hess Corporation (Hess) and Hess Investment Corp., a wholly-owned subsidiary of Hess (Merger
Sub). Pursuant to the terms of the Agreement, American will merge with Merger Sub, and upon
consummation of the merger the separate corporate existence of Merger Sub shall cease, and American
shall continue as the surviving corporation and a wholly-owned subsidiary of Hess (the Merger).
At the effective time of the Merger (the Closing), each share of American common stock will
be converted into the right to receive 0.1373 shares of Hess common stock. Hess will not assume any
stock options of American. Unvested stock options will become fully exercisable immediately prior
to the Closing, and holders of such options
may exercise their options or receive Hess shares as provided in the Agreement. In addition,
each share of American restricted stock will become fully vested prior to the Closing and will have
the same rights as each share of common stock not subject to any restrictions.
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The Agreement provides for a possible cash dividend to Americans stockholders to the extent
of Americans positive working capital as of the Closing Date, and subject to available cash.
Working capital will be determined in accordance with GAAP as Americans current assets less
current liabilities one business day prior to the Closing Date. Current liabilities also will
include the Americans transaction expenses and the amount required to be paid to terminate
Americans office lease that expires in May 2013 if determined or, if not determined, the present
value of the remaining obligations under Americans office lease. Current assets also will include
land acquisition costs paid by American after the date of the Merger Agreement with the prior
consent of Hess that do not involve existing contracts or outstanding offers as of the date of the
Merger Agreement, but will not include any cash or cash equivalents received by American in
connection with the exercise of any stock options or warrants after the date of the Merger
Agreement.
American, Hess and Merger Sub have made representations, warranties and covenants in the
Agreement, including covenants by American to conduct its business in the ordinary course and not
to engage in certain kinds of transactions and activities during the period between the execution
of the Agreement and the consummation of the Merger. American also has made certain additional
covenants, including, among others, covenants, subject to certain exceptions, (1) not to solicit
proposals regarding alternative business combination transactions, (2) not to enter into
discussions concerning, or provide confidential information in connection with, alternative
business combination transactions, (3) not to approve or recommend any alternative business
combination transaction proposals, (4) to cause a stockholder meeting to be held to consider
approval of the Merger and (5) for its Board of Directors to recommend approval of the Agreement by
Americans stockholders.
Each of the parties to the Agreement may terminate the Agreement upon the occurrence of
several events. Among other things, the Agreement may be terminated if (1) Americans Board of
Directors changes its recommendation to its common stockholders to approve the Merger, or
authorizes or endorses an Alternative Transaction (as defined in the Agreement), (2) the Agreement
is not adopted by the Americans stockholders, (3) the Merger is not completed by January 31, 2011
or (4) American directly or indirectly takes action to solicit an Alternative Transaction. Upon
termination of the Agreement under specified circumstances, American will be required to pay Hess a
termination fee of $13.5 million and reimburse expenses of Hess not to exceed $2.25 million. With
certain exceptions, all costs and expenses incurred in connection with the Agreement will be paid
by the party incurring such expenses, whether or not the Merger is consummated.
Completion of the Merger is conditioned upon, among other things, adoption of the Agreement by
Americans common stockholders and the accuracy of representations and warranties (subject to
materiality exceptions) as of the date of the Agreement and the Closing Date, and the performance
by the parties in all material respects of their covenants under the Agreement.
In connection with the Merger, certain officers, directors and 5% beneficial owners who own an
aggregate of approximately 20.5% of Americans common stock entered into voting agreements dated as
of July 27, 2010 (the Voting Agreement). Each Voting Agreement provides that each holder will
vote his shares in favor of the approval and adoption of the Merger Agreement and will not sell or
transfer his shares. Each Voting Agreement terminates at the Closing of the Merger or if the Merger
Agreement is terminated in accordance with its terms.
The Merger Agreement calls for American to use commercially reasonable efforts to sell
Americans Bigfoot properties to one or more third parties at fair market value and otherwise on
terms and conditions reasonably acceptable to Hess.
See
Notes 14 and 15 for discussion of lawsuits filed against American with regard to the merger
agreement.
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NOTE 11 HESS CREDIT FACILITY
In connection with the proposed Merger with Hess, Hess provided us with a senior secured
short-term revolving credit facility of $30 million (which facility has been expanded to $45
million) to help finance our exploration and production activities and other working capital needs
prior to closing of the Merger. We did not draw on the facility until October 1, 2010, when we
received $10,000,000. We borrowed an additional $2 million on November 1, 2010, and have requested
an additional $12 million to be funded on November 15, 2010. After the draw on November 15, 2010,
we will have $24 million outstanding and $21million available on the $45 million credit facility.
The current interest rate on the borrowings approximates 3.3% per annum, computed as 3% plus the
reserve adjusted one-month LIBOR rate.
NOTE 12 MATERIAL RELATED PARTY TRANSACTIONS
During August and September 2010, American sold to Hess 41,773 barrels of oil and 2,591 mcf of
gas for which the total oil and gas revenues were $2,704,762.
NOTE 13 ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE
Our $19,201,075 of accounts receivable at September 30, 2010, consisted of the following:
| Approximately $15.3 million in receivables from other working interest owners for
their share of capital expenditures and operating costs for wells and projects we
operate, |
| Approximately $3.1 million in accrued oil and gas revenues, net of production taxes,
at September 30, 2010 (including approximately $2.4 million due from Hess), |
| A$0.8 million receivable for remaining reimbursement of costs we had incurred on
behalf of an unrelated oil and gas company, and less |
| An allowance for doubtful accounts of $15,011. |
Our $18,369,405 of accounts payable and accrued liabilities at September 30, 2010, consisted
of the following:
| Approximately $10 million in invoiced trade payables, primarily for cost in
drilling and completing wells in North Dakota, including costs reimbursable to us from
other working interest owners in the wells we operate for various working interest
owner groups, and |
| Approximately $8 million in accrued liabilities, primarily for uninvoiced costs
incurred as of September 30, 2010 in the drilling and completion of wells in North
Dakota. |
In the Condensed Consolidated Statements of Cash Flows, the changes in accounts receivable and
accounts payable for cash used in operating activities exclude changes in payables and receivables
for capital expenditures.
NOTE 14 COMMITMENTS AND CONTINGENCIES
We may be subject to various possible contingencies, which are derived primarily from
interpretations of federal and state laws and regulations affecting the oil and gas industry.
Although management believes it has complied with the various laws and regulations, new rulings and
interpretations may require us to make future adjustments.
American has agreed to merge with Hess, subject to approval by a majority of Americans
stockholders, as described in Note 10. American, the members of Americans board of directors and
Hess are named as defendants in putative class action lawsuits brought by certain American
stockholders challenging Americans proposed merger with Hess. The lawsuits were filed in state
and federal courts in Colorado and in state court in Nevada. The lawsuits generally allege that
the members of Americans board of directors, aided and abetted by American and Hess, breached
their fiduciary duties to Americans stockholders by entering into the agreement and plan of merger
for the sale of American to Hess for what plaintiffs claim to be inadequate consideration and
pursuant to what plaintiffs claim to be an inadequate process. The lawsuits seek, among other things, to
enjoin the defendants from consummating the merger on the agreed-upon terms or to rescind the
merger to the extent already implemented.
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At September 30, 2010, American had a commitment to purchase by December 31, 2010 for
approximately $14.0 million (including sales tax) a variety of specific new casing and tubing to be
delivered to American by December 31, 2010 for use in wells to be drilled and completed by
American, as operator of those wells. The total fair value of the casing and tubing at September
30, 2010 slightly exceeded the future $14 million cost.
NOTE 15 SUBSEQUENT EVENTS
As
described in Part II, Item 1 of this Report, we entered into a Stipulation of Settlement with regards to
certain litigation involving the merger with Hess.
IMPORTANT ADDITIONAL
INFORMATION
Communications in this Form 10-Q do
not constitute an offer to sell or the solicitation of an offer to buy any
securities, or a solicitation of any vote or approval in respect of the
proposed merger transaction involving Hess and American. In connection with the
proposed transaction, Hess initially filed with the U.S. Securities and
Exchange Commission (the “SEC”) on August 23, 2010 a
registration statement on Form S-4 containing a preliminary proxy
statement/prospectus, and Hess filed an Amendment No. 1 to the
registration statement on Form S-4 on October 4, 2010. Each of Hess and
American also plan to file other documents with the SEC regarding the proposed
transaction. The proposed merger transaction involving Hess and American will
be submitted to American’s stockholders for their consideration and a
definitive proxy statement/prospectus will be mailed to American’s
stockholders. INVESTORS AND SECURITY HOLDERS OF AMERICAN ARE URGED TO READ
THE PROXY STATEMENT/PROSPECTUS AND OTHER DOCUMENTS REGARDING THE PROPOSED
TRANSACTION THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY
WHEN THEY BECOME AVAILABLE BECAUSE THEY DO AND WILL CONTAIN IMPORTANT
INFORMATION ABOUT THE PROPOSED TRANSACTION.
Investors and stockholders will be
able to obtain free copies of the proxy statement/prospectus and other
documents containing important information about Hess and American, once such
documents are filed with the SEC, through the website maintained by the SEC at
http://www.sec.gov. Copies of the documents filed with the SEC by Hess will be
available free of charge on Hess’ internet website at www.hess.com or by
contacting Hess’ Corporate Secretary Department at 212-536-8602. Copies
of the documents filed with the SEC by American will be available free of
charge on American’s internet website at www.americanog.com or by
contacting American’s Investor Relations Department at 303-449-1184.
Hess, American, their respective
directors and executive officers and other persons may be deemed to be
participants in the solicitation of proxies from the stockholders of American
in connection with the proposed transaction. Information about the directors
and executive officers of Hess is set forth in its proxy statement for its 2010
annual meeting of stockholders and in its annual report on Form 10-K, which
were filed with the SEC on March 25, 2010 and February 26, 2010,
respectively. Information about the directors and executive officers of
American is set forth in its proxy statement for its 2010 annual meeting of
stockholders and in its annual report on Form 10-K, as amended, which were
filed with the SEC on May 14, 2010 and March 15, 2010 (as amended on
March 29, 2010 and April 30, 2010), respectively. Other information
regarding the participants in the proxy solicitation and a description of their
direct and indirect interests, by security holdings or otherwise, will be
contained in the proxy statement/prospectus and other relevant materials to be
filed with the SEC when they become available.
The information in this Form 10-Q
shall not constitute an offer to sell or the solicitation of an offer to buy
any securities, a solicitation of any vote or approval, nor shall there be any
sale of securities in any jurisdiction in which such offer, solicitation or
sale would be unlawful prior to registration or qualification under the
securities laws of any such jurisdiction. No offering of securities shall be
made except by means of a prospectus meeting the requirements of
Section 10 of the Securities Act of 1933, as amended.
ITEM 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
On March 31, 2010, we sold all of our oil and gas interests in the Fetter and Krejci projects
located in the Power River Basin, Wyoming and received approximately $46.2 million in sales
proceeds on March 31 and an additional $1.7 million in early July, 2010. As a result of the sale,
our primary focus area is now our Goliath Bakken and Three Forks focused project located in
Williams County, North Dakota.
We have operated or participated in the drilling of 22 gross (12.9 net) wells thus far in the
Goliath project area in Williams County, North Dakota. We are currently operating a four-rig
drilling program and including wells-in- progress, have operated the drilling of a total of 16
gross (11.2 net wells) at Goliath, and six gross (1.7 net) wells have been drilled or are in
progress by other operators. We have also operated the drilling and completion of the currently
producing Summerfield 15-15H well (approximate 35% working interest), located in Dunn County, North
Dakota. Including the Summerfield well, we operate and own interests in five gross (3.05 net)
currently producing wells.
The table below presents the current status of our operated oil and natural gas drilling,
completion and production operations:
WELL NAME | LOCATION | STATUS | ||
Summerfield 15-15H WI=35% NRI=28.4% |
Sec. 15 T147N-R96W, Dunn County, ND |
Commenced production in May 2010. IP rate of 2,799 barrels of oil equivalent (BOE). Average daily rate for initial 30, 60, 90, 120 and 150 days of 1,046, 812, 693, 608 and 547 BOE, respectively. Total cumulative production at 10-31-2010 (167 actual production days) of 86,668 BOE (71,113 bbls of oil and 76 mmcf of natural gas). | ||
Tong Trust 1-20H WI=25.3% NRI=20.2% |
Sec. 20 T157N-R96W, Williams County, ND |
Commenced Production March 2010 at 1,421 BOE. Average daily rate for initial 30, 60, 90, 120 and 150 days of 652, 496, 401, 346 and 309 BOE, respectively. Total cumulative production at 11-5-2010 (173 actual production days) of 49,812 BOE (38,283 bbls of oil and 70 mmcf of natural gas). | ||
Ron Viall 1-25H WI=94% NRI=75.2% |
Sec. 25 T156N-R98W Williams County, ND |
Commenced production May 2010. IP rate of 2,844 BOE. Average daily rate for initial 30, 60, 90 and 120 days of 987, 739, 628 and 561BOE, respectively. Total cumulative production at 11-5-2010 (144 actual production days) of 76,534 BOE (56,075 bbls of oil and 123 mmcf of natural gas). |
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WELL NAME | LOCATION | STATUS | ||
Bergstrom 15-23H WI=95% NRI=76% |
Sec. 23 T156N-R98W Williams County, ND |
Commenced production August 2010. IP rate of 3,049 BOE. Average daily rate for initial 30 and 60 days of 1,061 and 860 BOE, respectively. Total cumulative production at 11-5-2010 (76 actual production days) of 58,875 BOE (45,861 bbls of oil and 78 mmcf of natural gas). | ||
Johnson 15-35H
WI=81.9%
NRI=65.5%
|
Sec. 35 T156N-R98W Williams County, ND |
Commenced production August 2010. Due to North Dakota Industrial Commission orders, production flow was choked back upon initial production due to excessive smoke from the flare. Average daily rate for initial 30 and 60 days of 806 and 711 BOE, respectively. Total cumulative production at 11-5-2010 (71 actual production days) of 47,348 BOE (36,188 bbls of oil and 67 mmcf of natural gas). | ||
Hickel 15-35H
WI=62.3%
NRI=49.8%
|
Sec. 35 T157N-R97W Williams County, ND |
Drilling operations concluded on July 27, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. Remedial work is underway to prepare this well for frac as frac crews are scheduled to commence completion in mid-November 2010. If this well is not ready for completion, frac crews may move to complete the Hodenfield 15-7H well. | ||
Hodenfield 15-33H
WI=57.4%
NRI=45.9%
|
Sec. 33 T157N-R97W Williams County, ND |
Drilling operations concluded on August 5, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. Fracture stimulation concluded on November 4, 2010. Temporary plugs are expected to be drilled out before November 15, 2010 and the well should commence production in mid-November 2010. | ||
Hodenfield 15-7H
WI=52.3%
NRI=41.8%
|
Sec. 7 T157N-R97W Williams County, ND |
Drilling operations concluded on August 14, 2010. Completion assembly installed to facilitate a 35-stage hydraulic fracture stimulation completion. Crews are expected to commence completion operations on or about November 15, 2010 and the well is expected to be placed on production prior to the end of November 2010. | ||
Bergstrom 2-27H
WI=72.9%
NRI=58.3%
|
Sec. 27 T156N-R98W Williams County, ND |
Drilling operations concluded on September 29, 2010. Completion assembly installed to facilitate a 27-stage hydraulic fracture stimulation completion. Crews are expected to commence completion operations immediately after completing the Hodenfield 15-7H well. | ||
Olson 15-36H
WI=68.2%
NRI=54.5%
|
Sec. 36 T157N-R98W Williams County, ND |
Drilling operations concluded on September 17, 2010. Completion assembly installed to facilitate a 32-stage hydraulic fracture stimulation completion. Frac crews are finalizing the completion to place the well on production. | ||
Hodenfield 15-23H
WI=55.3%
NRI=44.2%
|
Sec. 23 T157N-R98W Williams County, ND |
Drilling operations concluded on September 16, 2010. Completion assembly installed to facilitate a 30-stage hydraulic fracture stimulation completion. No completion date has been set. | ||
Reid 3-3H
WI=59.3%
NRI=47.4%
|
Sec. 3 T157N-R97W Williams County, ND |
Drilling operations concluded on October 17, 2010. Completion assembly installed to facilitate a 27-stage hydraulic fracture stimulation completion. No completion date has been set. |
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WELL NAME | LOCATION | STATUS | ||
Bergstrom 2-28H
WI=83.1%
NRI=66.5%
|
Sec. 28 T156N-R98W Williams County, ND |
Drilling operations also concluded on October 17, 2010. Completion assembly installed to facilitate a 22-stage hydraulic fracture stimulation completion. No completion date has been set. | ||
Dustin Brose 2-29H
WI=81.4%
NRI=65.1%
|
Sec. 29 T156N-R98W Williams County, ND |
Drilling operations concluded on November 7, 2010. Completion assembly installed to facilitate a 30-stage hydraulic fracture stimulation completion. No completion date has been set. | ||
Twilight 1-24H
WI=32.75%
NRI=26.2%
|
Sec. 24 T156N-R99W Williams County, ND |
Ensign drilling rig 24 commenced drilling on October 18, 2010 and is currently drilling in the lateral portion in the targeted Bakken formation. | ||
Haug 14-19H
WI=85.4%
NRI=68.3%
|
Sec. 19 T156N-R98W Williams County, ND |
Unit drilling rig 234 commenced drilling on October 23, 2010 and is currently drilling the vertical portion of the well. | ||
Dahl 15-22H
WI=64.5%
NRI=51.6%
|
Sec. 22 T156N-R97W Williams County, ND |
Ensign drilling rig 88 commenced drilling on October 25, 2010 and is currently cementing the 9-5/8 casing in the vertical portion of the well. | ||
Foss Family Trust 15-23H WI=51.4% NRI=41.1% |
Sec. 23 T156N-R97W Williams County, ND |
Preparations are underway to move Nabors drilling rig 486 from the Dustin Brose well location. This well is expected to commence drilling during the third week of November 2010. |
Results of Operations
The following discussion should be read in conjunction with the audited financial statements
and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31,
2009. It also should be read in conjunction with the financial statements and notes thereto
included in this report.
The Quarter Ended September 30, 2010 Compared with the Quarter Ended September 30, 2009
For the quarter ended September 30, 2010, we recorded a net loss of $119,266 ($0.00 per share,
basic and diluted), as compared to a net loss of $3,400,573 ($0.07 loss per common share, basic and
diluted) for the quarter ended September 30, 2009. The $3,281,307 decrease in net loss is
primarily due to (i) a $4.3 million increase in oil and gas revenues and (ii) $2.2 million in
reductions of impairments of oil and gas properties and supplies inventory, less (iii) a $2 million
increase in lease operating expenses and amortization expense and less (iv) approximately $1.2
million in general and administrative expenses directly related to investment banking and legal
services with regard to the July 27, 2010 agreement to merge with Hess Corporation, subject to
approval by Americans stockholders.
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For the quarter ended September 30, 2010, we recorded total oil and gas revenues of $4,806,383
compared with $462,553 for the quarter ended September 30, 2009. The $4,343,830 increase from the
2009 quarter is attributable to a 1,400% increase in oil production and significantly higher oil
and gas prices, partially offset by a decline in gas sales. Oil and gas sales and production costs
and other components of income from operations are summarized in the following table:
Three months ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Oil sold (barrels) |
73,112 | 4,877 | ||||||
Average oil price |
$ | 64.64 | $ | 59.17 | ||||
Oil revenue |
$ | 4,725,598 | $ | 288,567 | ||||
Gas sold (mcf) |
17,040 | 49,949 | ||||||
Average gas price |
$ | 4.74 | $ | 3.48 | ||||
Gas revenue |
$ | 80,785 | $ | 173,986 | ||||
Total oil and gas revenues |
$ | 4,806,383 | $ | 462,553 | ||||
Less lease operating expenses |
(912,493 | ) | (278,429 | ) | ||||
Less oil & gas amortization expense |
(1,601,000 | ) | (212,001 | ) | ||||
Less accretion of asset retirement obligation |
(3,741 | ) | (9,837 | ) | ||||
Less impairment of well equipment inventory |
(26,571 | ) | (409,852 | ) | ||||
Less impairment of oil & gas properties |
| (1,850,000 | ) | |||||
Income (loss) from oil & gas operations |
2,262,578 | (2,297,566 | ) | |||||
Less depreciation of office facilities |
(20,413 | ) | (19,416 | ) | ||||
Less amortization of other intangible asset |
| (45,000 | ) | |||||
Less general and administrative expenses |
(2,804,686 | ) | (1,198,188 | ) | ||||
Income (loss) from operations |
$ | (562,521 | ) | $ | (3,560,170 | ) | ||
Total barrels of oil equivalent (boe) sold |
75,952 | 13,202 | ||||||
Revenue per boe sold |
$ | 63.28 | $ | 35.04 | ||||
Lease operating expense per boe sold |
$ | 12.01 | $ | 21.09 | ||||
Amortization expense per boe sold |
$ | 21.08 | $ | 16.06 |
For the quarters ended September 30, 2010 and September 30, 2009, we incurred $2,804,686 and
$1,198,188, respectively, in general and administrative expenses. Total costs increased
approximately $1.6 million primarily due to (i) approximately $1.0 million paid for a third party
fairness opinion in July 2010 of the then-proposed merger with Hess Corporation and (ii) a $0.5
million increase in legal fees and expenses, primarily relating to the merger, including the
defense of lawsuits filed in connection with the merger.
The Nine-month Period ended September 30, 2010 Compared with the Nine-month Period ended
September 30, 2009
For the nine months ended September 30, 2010, we recorded net income of $27,661,320 ($0.46 per
share, basic and $0.45 per share, diluted), as compared to a net loss of $8,892,054 ($0.18 loss per
common share, basic and diluted) for the nine months ended September 30, 2009. The $36.6 million
increase in net income is primarily due to (i) a $36.4 million gain on the March 31, 2010 sale of
most of our Wyoming oil and gas properties, plus (ii) a $2 million increase in oil and gas
revenues, net of lease operating expenses and related oil and gas property amortization expense,
plus (iii) approximately $4 million reduction in impairments of oil and gas properties and supplies
inventories, less (iv)a $6.1 million increase in deferred income taxes.
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For the nine months ended September 30, 2010, we recorded total oil and gas revenues of
$8,083,918 compared with $1,285,705 for the nine months ended September 30, 2009. The $6,798,213
increase from the 2009 period is attributable to a 749% increase in oil production and
significantly higher oil and gas prices, partially offset by a decline in gas sales. Oil and gas
sales and production costs and other components of income from operations are summarized in the
following table:
Nine months ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Oil sold (barrels) |
119,374 | 14,056 | ||||||
Average oil price |
$ | 64.25 | $ | 46.87 | ||||
Oil revenue |
$ | 7,669,920 | $ | 658,759 | ||||
Gas sold (mcf) |
68,324 | 183,386 | ||||||
Average gas price |
$ | 6.06 | $ | 3.42 | ||||
Gas revenue |
$ | 413,998 | $ | 626,946 | ||||
Total oil and gas revenues |
$ | 8,083,918 | $ | 1,285,705 | ||||
Less lease operating expenses |
(1,777,764 | ) | (848,354 | ) | ||||
Less oil & gas amortization expense |
(2,551,000 | ) | (546,000 | ) | ||||
Less accretion of asset retirement obligation |
(16,849 | ) | (30,057 | ) | ||||
Less impairment of materials & supplies inventory |
(200,356 | ) | (565,991 | ) | ||||
Less impairment of oil & gas properties |
| (3,950,000 | ) | |||||
Plus gain on sale of oil and gas properties |
36,400,000 | | ||||||
Producing revenues less direct expenses |
39,937,949 | (4,654,697 | ) | |||||
Less depreciation of office facilities |
(60,011 | ) | (57,732 | ) | ||||
Less amortization of other intangible asset |
(60,000 | ) | (135,000 | ) | ||||
Less general and administrative expenses |
(6,168,688 | ) | (4,242,539 | ) | ||||
Income (loss) from operations |
33,649,250 | $ | (9,089,968 | ) | ||||
Total barrels of oil equivalent (boe) sold |
130,761 | 44,620 | ||||||
Revenue per boe sold |
$ | 61.82 | $ | 28.81 | ||||
Lease operating expense per boe sold |
$ | 13.60 | $ | 19.01 | ||||
Amortization expense per boe sold |
$ | 19.51 | $ | 12.24 |
For the nine months ended September 30, 2010 and September 30, 2009, we incurred $6,168,688
and $4,242,539, respectively, in general and administrative expenses. Total costs increased by
$1,926,149, primarily due to (i) an approximately $1.1 million increase in investment banking and
legal fees and expenses, primarily relating to the merger, including the defense of lawsuits filed
in connection with the merger and (ii) an approximately $0.8 million increase in employee
compensation.
Liquidity and Capital Resources
At September 30, 2010 and December 31, 2009, we had working capital of $17.9 million and $44.5
million, respectively. We had cash and cash equivalents at September 30, 2010 of $13.8 million.
For the calendar year ending December 31, 2010, including capital expenditures in the nine
months ended September 30, 2010 of $73.6 million, we anticipate spending a total of approximately
$129 million in capital expenditures, consisting primarily of (i) approximately $97 million
drilling and completing North Dakota wells to the Bakken formation or Three Forks formation at our
Goliath Project and (ii) approximately $32 million for North Dakota lease acquisitions and
extensions. Including wells already drilled or drilled and completed, we expect our 2010 drilling
program to consist of drilling 25 gross (14.5 net) wells. Due to the tightness of completion
crews, we expect to be able to complete twelve gross (7.1 net) wells in 2010.
In connection with the proposed Merger with Hess, Hess had provided us with a senior secured
short term revolving credit facility of $30 million to help finance our planned exploration and
production activities and other working capital needs prior to closing of the Merger. As of November
11, 2010, the credit facility was expanded to $45 million. As of September 30, 2010, we had not
borrowed on the facility. As of November 12, 2010 we had $12 million outstanding under the facility
and have requested an additional $12 million to be funded on November 15, 2010. After the
additional borrowing on November 15, 2010, we will have $24 million outstanding and $21million
available on the $45 million credit facility. As of November 12, 2010, we had approximately $12.9
million in cash and cash equivalents.
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As a result of our 2010 drilling program, we expect increased revenues from operations in
2010, compared to 2009, for the last three months of the year. We anticipate using (i) cash
currently on hand, (ii) cash from operations, (iii) advance payments for drilling and completion
costs from working interest partners and (iv) the $45 million credit facility from Hess Corporation
to pay for capital expenditures in the fourth quarter of 2010.
If the merger is
not complete by January 31, 2011, the merger will terminate pursuant to terms of the merger
agreement. We expect to have adequate capital to continue our operations through January 31, 2011.
If the merger term expires and the merger terminates, we are required to repay the borrowings
under the Hess senior secured short term revolving credit facility within 90 days and we expect to
need additional financing to repay these borrowings and for working capital. Such financing could
come from sale of additional debt, equity and or the sale of assets. We have not solicited and
have no commitments for financing, and the availability of financing is not assured. Any such
financing may be on terms that are not advantageous to us. All of our assets serve as collateral
for repayment of the borrowings from Hess.
The merger agreement with Hess provides for a possible cash dividend to Americans
stockholders to the extent of Americans positive working capital as of the closing date, and
subject to available cash (See Note 10 to our accompanying financial
statements). We do not expect
there will be positive working capital, as defined in the merger agreement, sufficient to pay a
dividend.
For the nine-month periods ended September 30, 2010 and September 30, 2009, our sources and
uses of cash were as follows:
Net Cash Provided (Used) By Operating Activities Our net cash used by operating
activities decreased by $361,956 (from $3,057,074 net cash used for operating activity for the
nine-month period ended September 30, 2009 to $2,695,118 cash used by operations for the nine-month
period ended September 30, 2010). Our cash received from oil and gas revenues in the 2010 period
were approximately $2 million greater than for the 2009 period. Our cash expenditures for general
and administrative expenses for the 2010 period were approximately $2 million greater than for the
2009 period. In the 2010 period, our net purchases of well equipment inventory held in third party
yards were approximately $315,000 less than in the 2009 period.
Net Cash Provided (Used) In Investing Activities During the nine-month period ended
September 30, 2010, investing activities used a net $24.9 million in cash as compared with $7.2
million of cash used by investing activities in the nine-month period ended September 30, 2009.
The $17.7 million increase in cash usage is primarily due to (i) our $63.8 million increase in
acquisition, exploration and development of our oil and gas properties (primarily in our Goliath
Project), less (ii) the $46.2 million received in March 2010 on the sale of oil and gas properties
in the Powder River Basin in Wyoming.
Net Cash Provided By Financing Activities During the nine-month periods ended
September 30, 2010 and September 30, 2009, the only financing activities were $804,150 in cash
received in the 2010 period relating to exercises of stock options and a warrant.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Price Risk
The Companys oil and gas business makes it vulnerable to changes in wellhead prices of crude
oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile
in the future. By definition, proved reserves are based on current oil and gas prices. Declines in
oil and gas prices reduce the estimated quantity of proved reserves and increase annual
amortization expense (which is based on proved reserves). Declines in oil and gas prices can reduce
the value of our oil and gas properties and increase impairment expense, as occurred in 2008 and
early 2009.
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We expect oil and gas price volatility to continue. We do not currently utilize hedging
contracts to protect against commodity price risk. As our oil and gas production grows, we may
manage our exposure to oil and natural gas price declines by entering into oil and natural gas
price hedging arrangements to secure a price for a portion of our expected future oil and natural
gas production.
Our operations are currently focused on drilling and completing wells in the Williston Basin
of North Dakota. Because the Williston basin is one of the most actively drilled basins in the
continental United States, production coming from the basin has been steadily increasing. Although
there are plans and projects underway to expand the take-away capacity (the ability to transport
oil out of the basin and to market) in the Williston Basin, we perceive that current take-away
capacity has not been expanding at a rate necessary to continue to transport all of the oil
production to market. We also perceive that production could expand beyond the take-away capacity
in the very near future. Should this occur, the basis differential (the price producers receive
for Williston basin oil production as compared to the higher West-Texas Intermediate price commonly
used as the benchmark oil price) could greatly increase. Should the basis differential for
Williston basin oil substantially increase, our oil revenue per barrel would decrease relative to
the benchmark oil price, and the economic profile of our drilling program would be negatively
affected.
Operating Cost Risk
During 2008, 2009 and 2010 to date, we have generally experienced fluctuations in operating
costs (including costs of drilling and completing wells) which impact our cash flow from operating
activities and profitability. Our drilling activity is focused on drilling oil wells with long
laterals in the Bakken and/or Three Forks formations in North Dakota. The North Dakota Williston
Basin is currently one of the most actively drilled basins in the continental United States.
There are currently upwards of 150 drilling rigs in operation targeting the Bakken and Three Forks
formations. We are experiencing increasing costs and difficulty in securing drilling and
completion services. We are also experiencing significant increases in costs for these services.
Fluctuations in drilling, completion and production costs, as well as fluctuations in oil and
gas prices can have a significant negative impact on our profitability and may negatively impact
how many wells we will drill in the Goliath project.
Interest Rate Risk
We currently have limited exposure to interest rate risk. At September 30, 2010, we had no
outstanding interest-bearing debt, but had a $30 million short-term credit facility from Hess
(which facility has been expanded to $45 million) for which the interest rate is a function of the
reserve adjusted one-month LIBOR rate. At September 30, 2010 we earn interest income on our cash
and cash equivalents at short-term rates of less than 1% per annum. Short-term dividend rates on
our $1,950,000 par value in Auction Rate Preferred Shares approximated 0.8% per annum and are at
rates which vary with short-term commercial paper and US LIBOR rates.
Item 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under
the supervision and with the participation of management, including our Chief Executive Officer and
Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the
end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and
Chief Financial Officer concluded that our disclosure controls and procedures were effective as of
September 30, 2010 to provide reasonable assurance that information required to be disclosed in our
reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and forms.
Disclosure controls and procedures, no matter how well designed and implemented, can provide
only reasonable assurance of achieving an entitys disclosure objectives. The likelihood of
achieving such objectives is affected by limitations inherent in disclosure controls and
procedures. These limitations include the fact that human judgment in decision-making can be faulty
and that breakdowns in internal control can occur because of human failures such as simple errors
or mistakes or because of intentional circumvention of the established process.
During the period covered by this report, there have been no changes in our internal controls
over financial reporting or in other factors, which could significantly affect internal controls
over financial reporting.
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PART II
OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
Litigation Relating to the Merger
American, the members of Americans board of directors, Hess and Merger Sub are named as
defendants in a number of putative class action lawsuits brought by certain American stockholders
challenging Americans proposed merger with Hess. The lawsuits were filed in state and federal
courts in Colorado and in state courts in Nevada. The lawsuits seek to certify a class of all
American stockholders (excluding defendants and related or affiliated persons or entities), and
generally allege that the members of Americans board of directors, aided and abetted by American
and Hess, breached their fiduciary duties to American stockholders by entering into the agreement
and plan of merger for the sale of American to Hess for allegedly inadequate consideration and
pursuant to an allegedly inadequate process. In particular, the complaints variously allege that
(i) the merger consideration is inadequate given Americans past and purported future economic
performance as compared to Hess past and purported future economic performance, (ii) the director
defendants will personally benefit from the vesting of illiquid or restricted stock options, (iii)
the voting and lockup agreements, termination fee, and non-solicitation provision of the agreement
and plan of merger improperly deter a superior, alternative offer from emerging, (iv) the agreement
and plan of merger did not contain a collar or pricing adjustment provision tied to Hess trading
price, and (v) Americans board of directors did not adequately explore alternative transactions.
The lawsuits seek, among other things, to enjoin the defendants from consummating the merger on the
agreed-upon terms or to rescind the merger to the extent already implemented.
The known cases filed to date include: (i) Edgar Cobb, Individually and on Behalf of All
Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01833-PAB, filed in the United
States District Court for the District of Colorado; (ii) Jeffrey P. Feinman, Individually and on
Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01846-MSK, filed in
the United States District Court for the District of Colorado; (iii) Morton Finkel, Individually
and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., 1:10-CV-01808-RPM,
filed in the United States District Court for the District of Colorado; (iv) Jeffrey Veigel,
Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al.,
1:10-CV-01852-MSK, filed in the United States District Court for the District of Colorado; (v)
Ernest Cox Wilkerson, Herb D. Johnson and Virginia Park, On Behalf of Themselves and All Others
Similarly Situated v. American Oil & Gas, et al., 2010-CV-6153, filed in the District Court of the
State of Colorado For the City and County of Denver; (vi) James Thurston, Individually and on
Behalf of All Others Similarly Situated v. Patrick D. OBrien, et al, 2010CV6141, filed in the
District Court of the State of Colorado For the City and County of Denver; (vii) Jeffrey Veigel,
Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al.,
1:10-CV-01852-MSK, filed in the District Court of the State of Colorado For the City and County of
Denver; (viii) Richard Buckman, Individually and on Behalf of All Others Similarly Situated v.
American Oil & Gas, et al., Case No. 10 DC 00322, filed in the First Judicial District Court of the
State of Nevada in and for Carson City; (ix) Ronald J. Kane, Individually and on Behalf of All
Others Similarly Situated v. American Oil & Gas, et al., Case No. A-10-622644-B, filed in the
Eighth Judicial District Court of the State of Nevada in and for Clark County; (x) Joseph Luvara,
Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, et al., Case No.
10-DC-0032-1B, filed in the First Judicial District Court of the State of Nevada in and for Carson
City; (xi) Roger Smitherman, Individually and on Behalf of All Others Similarly Situated v.
American Oil & Gas, et al., Case No. CV-10-02434, filed in the Second Judicial District Court of
the State of Nevada in and for County of Washoe; (xii) David Speight, Individually and on Behalf of
All Others Similarly Situated v. Patrick D. OBrien, et al., Case No. 10-DC-00340-1B, filed in the
Second Judicial District Court of the State of Nevada in and for Carson City; (xiii) Michael
Kunaman, Individually and on Behalf of All Others Similarly Situated v. American Oil & Gas, Inc.
et. al, Case No. 10-02484-B6, filed in the Second Judicial District Court of the State of Nevada in
and for the County of Washoe; (xiv) Michael Kunaman, Individually and on Behalf of All Others
Similarly Situated v. American Oil & Gas, Inc. et al., Case No. 10 OC 00435-1B, filed in the First
Judicial Court of the State of Nevada in and for the County of Carson City; (xv) Jorge Quiros,
Individually and on Behalf of All Others Similarly Situated v. Andrew Calerich et. al., Case No.
A-10-622573-C, filed in the Eighth Judicial District Court of the State of Nevada in and for Clark
County and (xvi) Colin Trueman, Individually and on Behalf of All Others Similarly Situated v.
American Oil & Gas, Inc. et al., Case No. A-10-624248-C, filed in the Eighth Judicial District
Court of the State of Nevada in and for Clark County.
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On September 24, 2010, the Speight court entered an order dismissing the claims against
American, Hess Investment Corporation, and Hess on grounds of forum non conveniens, and a motion to
dismiss as to the Individual Directors is pending. The Kane action was voluntarily dismissed on
September 9, 2010.
The Buckman, Luvara, Smitherman, Quiros, and Trueman actions were removed by Defendants to
Nevada federal court, and the parties are contesting whether the cases should be transferred to
federal court in Colorado or remanded back to Nevada state court.
In the Cobb, Veigel, Finkel, and Feinman actions, the parties held discovery conferences
before Magistrate Judge Kathleen Tafoya, who approved an expedited discovery stipulation. Document
and deposition discovery has begun. On October 5, 2010, the Colorado federal court (the Court)
consolidated the Cobb, Veigel, Finkel, and Feinman actions under the caption Finkel v. American Oil
& Gas, Inc., No. 10-cv-1808-CMA-MEH (the Consolidated Colorado Federal Action), and a
consolidated complaint was filed by the plaintiffs on October 29, 2010. The Cobb Action was
dismissed without prejudice. On October 15, 2010, plaintiffs in the Consolidated Colorado Federal
Action filed a Motion for Preliminary Injunction seeking to enjoin the proposed merger.
Settlement of Litigation Relating to the Merger
On November 12, 2010, plaintiffs in the Consolidated Colorado Federal Action, and the Buckman,
Luvara, and Kunaman actions pending in federal and state court in Nevada, on behalf of themselves
and the Settlement Class, entered into the Stipulation of Settlement with the defendants to fully
and finally resolve the Settlement Class members claims challenging the proposed merger.
Pursuant to the Stipulation of Settlement, and in exchange for the releases by the plaintiffs
and the Settlement Class described below, Hess and American have included plaintiffs counsel in
the disclosure process, and Hess and American are to make certain supplemental disclosures in the
forthcoming amendment to Hesss Form S-4 filing with the SEC and in the forthcoming proxy statement
to Americans stockholders. The supplemental disclosures address issues identified by plaintiffs.
As part of the negotiated settlement, defendants agreed not to object to an attorneys fees
application by plaintiffs counsel up to $200,000. Defendants also agreed to pay plaintiffs
attorneys fees and expenses in an amount awarded by the Court not to exceed $850,000.
Pursuant to the Stipulation of Settlement, the Settlement Class will release all the
defendants from any and all claims relating to, among other things, the merger, the agreement and
plan of merger and any disclosures made in connection therewith. The Consolidated Colorado Federal
Action will be also dismissed with prejudice on the merits by the Court upon final approval of the
settlement. The Stipulation of Settlement is subject to customary conditions, including the
consummation of the merger, class certification of the Settlement Class, and final approval by the
Court, following notice to the stockholders of American.
The settlement will not affect the form or amount of consideration to be received by American
stockholders in the merger.
The defendants have denied and continue to deny any wrongdoing or liability with respect to
all claims, events and transactions complained of in the aforementioned litigations or that they
have engaged in any wrongdoing. The defendants have entered into the Stipulation of Settlement to
(i) eliminate the burden and expense of further litigation, (ii) put the released claims to rest,
finally and forever, without in any way acknowledging wrongdoing, fault, liability, or damage to
the Settlement Class, and (iii) permit the proposed merger to close without risk of injunctive or
other relief.
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Table of Contents
The foregoing description is a summary of material terms of the Stipulation of Settlement, a
copy of which has been attached as an exhibit.
Americans Arbitration Claim Against Jefferies
On August 6, 2009, American filed with the Financial Industry Regulatory Authority (FINRA) a
statement of claim against Jefferies & Company, Inc. (Jefferies), as Americans broker with
regards to the ARPS. The statement of claim seeks in arbitration to have Jefferies (i) purchase at
par value Americans remaining unredeemed ARPS, (ii) reimburse American for consequential damages
(approximating $150,000 to date) and for Americans legal costs in the arbitration and (iii) pay
American approximately $1 million in interest at 8% per annum under Colorado statute C. R. S. §
5-12-102, less the ARPS dividends American received following the failed auctions. The
arbitration hearing is scheduled currently to take place in June 2011.
Item 6. EXHIBITS
Exhibit No. | Description | |||
2.1 | Credit Agreement dated as of August 27, 2010 between American Oil & Gas Inc. and
Hess Corporation (Incorporated by reference from the Companys Current Report on
Form 8-K, filed on August 30, 2010) |
|||
2.2 | Security Agreement dated as of August 27, 2010 and entered into by and among
American Oil & Gas Inc. and each Additional Grantor and the Hess Corporation
(Incorporated by reference from the Companys Current Report on Form 8-K, filed
on August 30, 2010) |
|||
2.3 | Form of Mortgage, Security Agreement, Financing Statement and Assignment of
Production from American Oil & Gas Inc. to Hess Corporation, dated effective as
of August 27, 2010 (Incorporated by reference from the Companys Current Report
on Form 8-K, filed on August 30, 2010) |
|||
2.4 | Form of Loan Notice, Note, Form of Compliance Certificate and Solvency Certificate (Incorporated by reference from the Companys Current Report
on Form 8-K, filed on August 30, 2010) |
|||
2.5 | Amendment (dated as of November 11, 2010) to the Credit Agreement dated as of
August 27, 2010 between American Oil & Gas Inc. and Hess
Corporation |
|||
10 | (i) | Agreement and Plan of Merger dated as of July 27, 2010 among Hess Corporation,
Hess Investment Corp. and American Oil & Gas Inc. (Incorporated by reference from
the Companys Current Report on Form 8-K, filed on July 29, 2010) |
||
10 | (ii) | Stipulation and Agreement of Settlement and Release (November 2010) |
||
31.1 | 302 Certification of Chief Executive Officer |
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31.2 | 302 Certification of Chief Financial Officer |
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32.1 | 906 Certification of Chief Executive Officer |
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32.2 | 906 Certification of Chief Financial Officer |
SIGNATURES
In accordance with the requirements of the Exchange Act, the Registrant has caused this report
to be signed on its behalf by the undersigned, thereunto duly authorized.
Signatures | Title | Date | ||
/s/ Patrick D. OBrien
|
Chief Executive Officer and Chairman of The Board of Directors | November 12, 2010 | ||
/s/ Joseph B. Feiten
|
Chief Financial Officer | November 12, 2010 | ||
(principal financial officer and principal accounting officer) |
25