UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended July 31, 2010
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from ____________ to ____________
Commission file number: 001-34732
MILLER PETROLEUM, INC.
----------------------
(Exact name of registrant as specified in its charter)
TENNESSEE 62-1028629
--------- ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
3651 BAKER HIGHWAY, HUNTSVILLE, TN 37756
---------------------------------- -----
(Address of principal executive offices) (Zip Code)
(423) 663-9457
--------------
(Registrant's telephone number, including area code)
N/A
---
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T during the
preceding 12 months (or for such shorter period of time that the registrant was
required to submit and post such files) [ ] Yes [ ] No
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [ ] Smaller reporting company [X]
(Do not check if smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Title of Class No. of Shares Outstanding at September 7, 2010
-------------- -----------------------------------------------
Common Stock 33,434,838
MILLER PETROLEUM, INC.
FORM 10-Q
JULY 31, 2010
TABLE OF CONTENTS
Page
No.
----
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
Summary Financial Data at July 31, 2010 (Unaudited),
April 30, 2010, January 31, 2009 (Unaudited) and
October 31, 2009 (Unaudited)..................................... 4
Consolidated Balance Sheets at July 31, 2010 (Unaudited) and
April 30, 2010................................................... 6
Consolidated Statements of Operations for the Three months ended
July 31, 2010 (Unaudited) and 2009 (Unaudited)................... 8
Consolidated Statements of Cash Flows for the Three months ended
July 31, 2010 and 2009 (Unaudited)............................... 9
Notes to Consolidated Financial Statements (Unaudited)............. 10
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................ 21
Item 3. Quantitative and Qualitative Disclosures About Market Risk......... 28
Item 4. Controls and Procedures............................................ 28
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.................................................. 28
Item 1A. Risk Factors....................................................... 28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds........ 29
Item 3. Defaults Upon Senior Securities.................................... 29
Item 4. (Removed and Reserved)............................................. 29
Item 5. Other Information.................................................. 29
Item 6. Exhibits........................................................... 29
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This report contains forward-looking statements. These forward-looking
statements are subject to known and unknown risks, uncertainties and other
factors which may cause actual results, performance or achievements to be
materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. These forward-looking
statements were based on various factors and were derived utilizing numerous
assumptions and other factors that could cause our actual results to differ
materially from those in the forward-looking statements. These factors include,
but are not limited to:
o the capital intensive nature of oil and gas development and exploration
operations and our ability to raise adequate capital to fully develop
our operations and assets,
o our ability to perform under the terms of the Assignment Oversight
Agreement with the Alaska DNR, including meeting the funding
commitments of that agreement,
2
o fluctuating oil and gas prices and the impact on our results of
operations,
o our ability to secure an extension of the Susitna Basin Exploration
License,
o the impact of the global economic crisis on our business,
o the impact of natural disasters on our Cook Inlet Basin operations,
o the imprecise nature of our reserve estimates,
o our ability to recover proved undeveloped reserves and convert probable
and possible reserves to proved reserves,
o the possibility that present value of future net cash flows will not be
the same as the market value,
o the costs and impact associated federal and state regulations,
o changes in existing federal and state regulations,
o our dependence on third party transportation facilities,
o insufficient insurance coverage,
o conflicts of interest related to our dealings with MEI,
o cashless exercise provisions of outstanding warrants,
o market overhang related to restricted securities and outstanding
options, warrants and convertible notes, and
o adverse impacts on the market price of our common stock from sales by
the holders of our common stock and warrants purchased in recent
private offerings.
Most of these factors are difficult to predict accurately and are
generally beyond our control. You should consider the areas of risk described in
connection with any forward-looking statements that may be made herein or in our
Annual Report on Form 10-K for the year ended April 30, 2010. Readers are
cautioned not to place undue reliance on these forward-looking statements and
readers should carefully review this report in its entirety. Except for our
ongoing obligations to disclose material information under the Federal
securities laws, we undertake no obligation to release publicly any revisions to
any forward-looking statements, to report events or to report the occurrence of
unanticipated events. These forward-looking statements speak only as of the date
of this report, and you should not rely on these statements without also
considering the risks and uncertainties associated with these statements and our
business.
OTHER PERTINENT INFORMATION
Unless specifically set forth to the contrary, when used in this report
the terms the "Company," "we," "us," "ours," and similar terms refers to Miller
Petroleum, Inc., a Tennessee corporation doing business as Miller Energy
Resources and our subsidiaries, Miller Rig & Equipment, LLC, Miller Drilling TN,
LLC and Miller Energy Services, LLC, East Tennessee Consultants, Inc., East
Tennessee Consultants II, LLC, Miller Energy GP, LLC, and Cook Inlet Energy,
LLC.
The information which appears on our web site at www.millerenergyresources.com
is not part of this report.
3
PART 1 - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
MILLER PETROLEUM, INC.
SUMMARY FINANCIAL INFORMATION
(UNAUDITED)
For the Three For the Three
Months Ended Months Ended
July 31, July 31,
2010 2009
------------- -------------
Revenue
Oil and gas revenue .................. $ 4,791,179 $ 404,392
Service and drilling revenue ......... 409,068 123,228
------------- -------------
Total ................................ 5,200,247 527,620
Direct Expenses
Oil and gas .......................... 2,304,107 24,044
Service and drilling ................. 495,747 244,500
Depletion expense .................... 1,576,848 117,434
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Total ................................ 4,376,702 385,978
------------- -------------
Gross Profit ......................... 823,545 141,642
Selling, general and administrative .. 2,766,673 652,391
Depreciation and amortization ........ 413,824 111,727
LOSS FROM OPERATIONS ................. (2,356,952) (622,476)
Total other income ................... 2,613,292 693,911
NET INCOME ........................... $ 682,907 $ 72,213
4
MILLER PETROLEUM, INC.
SUMMARY FINANCIAL INFORMATION
(UNAUDITED)
(continued)
July 31, April 30, January 31, October 31,
2010 2010 2010 2009
(Unaudited) (Unaudited) (Unaudited)
------------- ------------- ------------- -------------
Cash .............................. $ 472,543 $ 2,750,841 $ 2,508,186 $ 94,838
Cash, restricted .................. 126,379 126,064 131,499 1,982,489
------------- ------------- ------------- -------------
Total Cash ........................ 598,922 2,876,905 2,639,685 2,077,327
Oil and Gas Properties ............ 378,509,510 376,216,621 371,725,938 4,047,713
Total Assets ...................... 500,921,122 500,452,155 493,244,733 12,456,570
Total Current Liabilities ......... 6,053,165 4,828,333 1,284,932 3,743,949
Total Long-term Liabilities ....... 217,331,590 219,883,001 201,350,622 545,524
Total Stockholders' Equity ........ 277,536,367 275,740,821 290,609,179 8,167,097
Total Gross Producing Oil Wells ... 186 188 196 194
Total Gross Producing Gas Wells ... 323 337 249 263
------------- ------------- ------------- -------------
Total Gross Producing Wells........ 509 525 445 457
Gross Oil/Gas Lease/License Acreage 634,219 645,683 657,170 54,506
Net Oil/Gas Lease/License Acreage . 597,224 603,546 610,728 54,506
Total Proved Oil Reserves MBOE .... 10.344 (1) 10.344 (1) 9.578 (2) 0.129 (3)
Total Proved Gas Reserves MBOE .... 0.910 (1) 0.910 (1) 1.149 (2) 0.335 (3)
Total Proved, Probable, Possible
Oil Reserves MBOE ............... 17.634 (1) 17.634 (1) 16.602 (2) 0.168 (3)
Total Proved Probable, Possible
Gas Reserves MBOE ............... 3.321 (1) 3.321 (1) 2.652 (2) 0.335 (3)
(1) Based on Reserve Reports dated April 30, 2010.
(2) Based on Reserve Reports dated April 30, 2009, June 8, 2009, June 18, 2009,
October 31, 2009, and December 10, 2009
(3) Based on Reserve Reports dated April 30, 2009, June 8, 2009, June 18, 2009
and October 31, 2009.
5
MILLER PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
July 31, April 30,
2010 2010
Unaudited
------------ ------------
CURRENT ASSETS
Cash .......................................... $ 472,543 $ 2,750,841
Cash, restricted .............................. 126,379 126,064
Accounts receivable, net ...................... 1,444,047 1,444,844
Accounts receivable - related parties ......... 45,573 47,446
Inventory ..................................... 767,678 521,639
Prepaid expenses .............................. 177,556 275,610
------------ ------------
Total Current Assets .......................... 3,033,776 5,166,444
Fixed Assets .................................. 116,953,563 116,782,535
Less: accumulated depreciation ................ (2,375,580) (1,961,756)
------------ ------------
Net Fixed Assets .............................. 114,577,983 114,820,779
OIL AND GAS PROPERTIES
(On the basis of successful efforts accounting) 378,509,510 376,216,621
Land .......................................... 526,500 526,500
Cash - restricted, long-term .................. 2,070,445 2,071,839
Other assets .................................. 2,202,908 1,649,972
------------ ------------
Total Other Assets ............................ 4,799,853 4,248,311
------------ ------------
TOTAL ASSETS .................................. $500,921,122 $500,452,155
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
6
MILLER PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
July 31, April 30,
2010 2010
Unaudited
------------ ------------
CURRENT LIABILITIES
Accounts payable - trade ...................... $ 5,244,203 $ 3,579,112
Accrued expenses .............................. 440,570 421,938
Current derivative liability .................. 326,950 720,840
Unearned revenue .............................. 41,442 106,443
------------ ------------
Total Current Liabilities ..................... 6,053,165 4,828,333
LONG-TERM LIABILITIES
Deferred income taxes payable ................. 184,367,963 184,468,878
Asset retirement liability .................... 15,662,003 15,662,002
Long term derivative liability ................ 14,196,880 16,708,947
Notes payable, related parties, net ........... 2,219,323 1,803,775
Notes payable - other, net .................... 885,421 1,239,399
------------ ------------
Total Long-term Liabilities ................... 217,331,590 219,883,001
------------ ------------
Total Liabilities ............................. 223,384,755 224,711,334
STOCKHOLDERS' EQUITY
Common stock, 500,000,000 shares authorized at
$0.0001 par value, 33,389,383 and 32,224,894
shares issued and outstanding, respectively 3,339 3,223
Additional paid-in capital .................... 28,733,128 27,620,605
Retained earnings ............................. 248,799,900 248,116,993
------------ ------------
Total Stockholders' Equity .................... 277,536,367 275,740,821
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .... $500,921,122 $500,452,155
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
7
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
For the Three For the Three
Months Ended Months Ended
July 31, July 31,
2010 2009
------------ ------------
REVENUES
Oil and gas revenue ........................... $ 4,791,179 $ 404,392
Service and drilling revenue .................. 409,068 123,228
------------ ------------
Total Revenue ................................. 5,200,247 527,620
COSTS AND EXPENSES
Cost of oil and gas revenue ................... 2,304,107 24,044
Cost of service and drilling revenue .......... 495,747 244,500
Selling, general and administrative ........... 2,766,673 652,391
Depreciation, depletion and amortization ...... 1,990,672 229,161
------------ ------------
Total Costs and Expenses ...................... 7,557,199 1,150,096
------------ ------------
LOSS FROM OPERATIONS .......................... (2,356,952) (622,476)
OTHER INCOME (EXPENSE)
Interest income ............................... 4,553 7,971
Interest expense .............................. (219,338) (12,869)
Gain on derivative securities.................. 2,905,957 -
Loan fees and costs............................ (90,380) (52,636)
Loss on sale of equipment...................... - (9,755)
Gain on sale of properties..................... 12,500 -
Gain on acquisitions .......................... - 761,200
------------ ------------
Total Other Income ............................ 2,613,292 693,911
------------ ------------
NET INCOME BEFORE INCOME TAXES ................ 256,340 71,435
INCOME TAX BENEFIT............................. (426,567) (778)
------------ ------------
NET INCOME..................................... $ 682,907 $ 72,213
============ ============
INCOME PER SHARE
BASIC ....................................... $ 0.02 $ 0.00
DILUTED ..................................... $ 0.02 $ 0.00
WEIGHTED AVERAGE SHARES OUTSTANDING
BASIC ....................................... 32,835,722 17,271,639
DILUTED ..................................... 40,591,670 17,271,639
The accompanying notes are an integral part of these
consolidated financial statements.
8
MILLER PETROLEUM, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
For the Three For the Three
Months Ended Months Ended
July 31, 2010 July 31, 2009
------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income ......................................... $ 682,907 $ 72,213
Depreciation, depletion and amortization ......... 1,990,672 229,161
Adjustments to Reconcile Net Loss to Net Cash
Provided (Used) by Operating Activities:
Loss (gain) on sale of equipment ................. -- 9,755
Gain on acquisitions ............................. -- (761,200)
Derivative liability, net ........................ (2,905,957) --
Prepaid offering cost ............................ -- (99,037)
Issuance of equity for compensation .............. 515,891 --
Issuance of equity for financing costs ........... -- 38,624
Changes in Operating Assets and Liabilities:
Accounts receivable ............................ 2,670 (67,342)
Inventory ...................................... (246,039) (143,251)
Prepaid expense ................................ 98,054 (97,613)
Accounts payable ............................... 1,665,091 251,311
Accrued expenses ............................... 18,633 191,309
Unearned revenue ............................... (65,001) 5,653
Income taxes payable ........................... (100,915) --
Deferred interest .............................. -- 616
Other assets ................................... (275,076) --
------------ ------------
Net Cash Provided (Used) by Operating Activities 1,380,930 (369,801)
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of equipment and improvements ........... (171,028) (25,892)
Capital expenditures for oil and gas properties (3,869,738) (18,112)
Sale of oil and gas properties ................... -- 25,000
Proceeds from sale of equipment .................. -- 50,000
------------ ------------
Net Cash Provided (Used) by Investing Activities (4,040,766) 30,996
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on notes payable ........................ -- (5,672)
Deferred financing assets ........................ (46,290) --
Proceeds from borrowing .......................... 350,000 235,266
Proceeds from sale of stock, net ................. -- 119,000
Cash acquired through acquisition ................ -- 203,993
Exercise of equity rights ........................ 76,749 --
Restricted cash .................................. (315) 6,042
Restricted cash non-current ...................... 1,394 (166,372)
------------ ------------
Net Cash Provided by Financing Activities ........ 381,538 392,257
------------ ------------
NET INCREASE (DECREASE) IN CASH .................... (2,278,298) 53,452
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ..... 2,750,841 46,566
------------ ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD ........... $ 472,543 $ 100,018
============ ============
CASH PAID FOR INTEREST ............................. $ 221,541 $ 87,526
CASH PAID FOR TAXES ................................ $ -- $ --
SUPPLEMENTAL DISCLOSURE OF NON CASH FINANCING ITEMS:
Financing costs from issuance of warrants and stock $ -- $ 38,624
Cash acquired through issuance of stock ............ $ -- $ 203,993
Restricted cash acquired through issuance of stock $ -- $ 196,682
Net assets acquired through issuance of stock ...... $ -- $ 930,525
Conversion of debt for equity ...................... $ 520,000 $ --
Common stock issued for prepaid offering costs ..... $ -- $ 115,000
The accompanying notes are an integral part of these
consolidated financial statements.
9
MILLER PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(1) ORGANIZATION AND DESCRIPTION OF BUSINESS
These consolidated financial statements include the accounts of Miller
Petroleum, Inc. (the "Company") and the accounts of its subsidiaries, Miller
Drilling TN, LLC, Miller Energy Services, LLC, East Tennessee Consultants, Inc.
and East Tennessee Consultants II, LLC for the comparative periods ended July
31, 2010 and 2009. Miller Petroleum, Inc.'s subsidiaries Miller Energy GP, LLC
and Cook Inlet Energy, LLC were included in the consolidation for the period
ended July 31, 2010 only, since these subsidiaries started up subsequent to the
three months ended July 31, 2009. All inter-company balances have been
eliminated in consolidation.
The Company's principal business consists of oil and gas exploration, production
and related property management in the Appalachian region of eastern Tennessee
as well as in the Cook Inlet Basin of Alaska. The Company's corporate offices
are in Huntsville, Tennessee. The Company operates as one reportable business
segment, based on the similarity of activities.
Certain information and footnote disclosures normally included in the financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted. It is suggested that these financial statements
be read in conjunction with the Company's April 30, 2010 Annual Report on Form
10-K. The results of operations for the period ended July 31, 2010 are not
necessarily indicative of operating results for the full year. In the opinion of
management, all adjustments (consisting of only normal recurring accruals)
considered necessary for a fair presentation have been included.
(2) ACCOUNTING POLICIES
RECLASSIFICATIONS
Certain reclassifications have been made to the prior period amounts presented
to conform to the current period presentations.
PRINCIPLES OF CONSOLIDATION AND NON-CONTROLLING INTEREST
The consolidated financial statements include the accounts of the Company and
its subsidiaries, all of which are wholly-owned at July 31, 2010 except for
Miller Energy Income, 2009-A, LP("MEI"), which is controlled by the Company. The
non-controlling ownership interests in the net income (loss) are reflected
within non-controlling interests on the Company's consolidated statements of
operations. The non-controlling interests in the assets and liabilities of MEI
are reflected as a component of stockholders' equity on the Company's
consolidated balance sheets. All material intercompany transactions have been
eliminated.
USE OF ESTIMATES
The preparation of the Company's consolidated financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities that
exist at the date of the Company's consolidated financial statements, as well as
the reported amounts of revenue and costs and expenses during the reporting
periods. The Company's consolidated financial statements are based on a number
of significant estimates, including the revenue and expense accruals, deferred
tax assets and liabilities, depletion, depreciation and amortization, asset
impairments, the probability of forecasted transactions and the allocation of
purchase price to the fair value of assets acquired. Actual results could differ
from those estimates.
10
The natural gas industry principally conducts its business by processing actual
transactions as much as 60 days after the month of delivery. Consequently, the
most recent two months' financial results were recorded using estimated volumes
and contract market prices. Differences between estimated and actual amounts are
recorded in the following month's financial results. Management believes that
the operating results presented for the three months ended July 31, 2010
represent actual results in all material respects.
IMPAIRMENT OF LONG-LIVED ASSETS
The Company reviews its long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. If it is determined that an asset's estimated future cash flows
will not be sufficient to recover its carrying amount, an impairment charge will
be recorded to reduce the carrying amount for that asset to its estimated fair
value if such carrying amount exceeds the fair value.
The review of the Company's oil and gas properties is done by determining if the
historical cost of proved properties less the applicable accumulated depletion,
depreciation and amortization and abandonment is less than the estimated
expected undiscounted future cash flows. The expected future cash flows are
estimated based on the Company's plans to continue to produce and develop proved
reserves. Expected future cash flow from the sale of production of reserves is
calculated based on estimated future prices. The Company estimates prices based
upon current contracts in place, adjusted for basis differentials and market
related information including published futures prices. The estimated future
level of production is based on assumptions surrounding future prices and costs,
field decline rates, market demand and supply and the economic and regulatory
climates. If the carrying value exceeds the expected future cash flows, an
impairment loss is recognized for the difference between the estimated fair
market value (as determined by discounted future cash flows) and the carrying
value of the assets.
The determination of oil and natural gas reserve estimates is a subjective
process, and the accuracy of any reserve estimate depends on the quality of
available data and the application of engineering and geological interpretation
and judgment. Estimates of economically recoverable reserves and future net cash
flows depend on a number of variable factors and assumptions that are difficult
to predict and may vary considerably from actual results
Oil and gas properties are reviewed annually for impairment or whenever events
or circumstances indicate that the carrying amount of an asset may not be
recoverable. Impairment charges are recorded if conditions indicate the Company
will not explore the acreage prior to expiration of the applicable leases or if
it is determined that the carrying value of the properties is above their fair
value. There were no impairments of oil and gas properties or unproved
properties recorded by the Company for the three months ended July 31, 2010 and
2009.
INVENTORY
Inventory consists primarily of crude oil in tanks and is carried at the lower
of cost or market on a "FIFO" basis.
RECENT ACCOUNTING PRONOUNCEMENTS
All issued, but not yet effective accounting pronouncements are determined to be
not applicable or significant by management and once adopted is not expected to
have a material impact on the financial position of the Company.
11
(3) SALE OF OIL AND GAS PROPERTIES AND EQUIPMENT PURCHASES
On June 13, 2008 we sold approximately 30,000 acres of oil and gas leases and
eight drilled but not completed wells to Atlas America, LLC ("Atlas") for
$19.625 million. At that time Wind City Oil & Gas, LLC and related entities were
paid $10.6 million for 2.9 million shares of the Company's common stock, eight
drilled but not completed gas wells, two producing gas wells, and a RD20
drilling rig and related equipment in settlement of all litigation between the
parties.
On November 10, 2008, the Company finalized a drilling contract with Atlas
Energy Resources, LLC, an affiliate of Atlas. This is a two year agreement that
will utilize two of the Company's drilling rigs operating in the East Tennessee
area of the Appalachian Basin. We acquired a 2007 COPCO Model RD III drilling
rig and related equipment from Atlas to assist in drilling the wells. This rig
has been mobilized to the site and has commenced drilling operations. The
Company borrowed $1,850,125, secured by a certificate of deposit, to purchase
this drilling rig. As of January 31, 2010, the debt was paid in full.
After the sale was completed, the Company paid off all notes, all undisputed
payables, transaction fees of $600,000 to Cresta Capital/Consortium, and paid a
transaction fee of $300,000 and issued 2,500,000 shares of common stock valued
at $825,000 to Mr. Scott Boruff, a former associate of Cresta Capital. Mr.
Boruff was subsequently hired effective August 1, 2008 as the new CEO of the
Company (see Commitments note below). He is a son-in-law of Deloy Miller the
former CEO and current Chairman of the Board of Directors. Cresta was also
granted a warrant to purchase one million shares of the Company's common stock
for $1.00 per share for a period expiring three years after the grant date and
cancelled the five million performance warrants that it held.
The net gain on this sale of oil and gas property transaction was $11,715,570.
A third party interested in aforementioned sale of the oil and gas properties is
contesting the sale, see the Litigation note below.
(4) PARTICIPANT RECEIVABLES AND RELATED PARTY RECEIVABLES
Participant and related party receivables consist of receivables contractually
due from our various joint venture partners in connection with routine
exploration, betterment and maintenance activities. Our collateral for these
receivables generally consists of lien rights over the related oil producing
properties at both July 31, 2010 and April 30, 2010.
The Company had an account receivable from a member of the Board of Directors,
and his family, at July 31, 2010 and April 30, 2010 in the amounts of $30,956
and $29,950, respectively for work performed on oil and gas wells. This board
member and his wife own partial interests in the oil and gas wells the Company
also owns.
The Company had notes payable at and July 31, 2010 and April 30, 2010 of
$3,071,444 and $2,721,444, respectively, to MEI. MEI's general partner is Miller
Energy GP, LLC, a 100% owned subsidiary of the Company.
12
(5) FIXED ASSETS
Fixed assets consist of the following:
July 31, April 30,
2010 2010
------------- -------------
Machinery & Equipment ............ $ 4,768,658 $ 4,620,219
Pipelines ........................ 17,000,000 17,000,000
Oil platform ..................... 6,000,000 6,000,000
Vehicles ......................... 1,418,414 1,402,094
Buildings ........................ 87,682,810 87,682,810
Office Equipment ................. 83,681 77,411
------------- -------------
116,953,563 116,782,534
Less: accumulated depreciation ... (2,375,580) (1,961,755)
------------- -------------
Net Fixed Assets ................. $ 114,577,983 $ 114,820,779
The increase in Machinery and Equipment primarily resulted from purchase of a
rig. The increase in vehicles resulted from the purchase of two used trucks. The
increase in office equipment primarily resulted from the purchase of new
accounting software and new computers. Depreciation expense for the three months
ended July 31, 2010 and 2009 was $413,824 and $111,727 respectively.
(6) DERIVATIVE LIABILITIES
Effective May 1, 2009, the Company adopted the provisions of EITF 07-05
"Determining Whether an Instrument (or Embedded Feature) is Indexed to a
Company's Own Stock," which was codified into ASC Topic 815 - Derivatives and
Hedging. ASC 815 applies to any freestanding financial instruments or embedded
features that have characteristics of a derivative and to any freestanding
financial instruments that are potentially settled in an entity's own common
stock. The Company has 4,016,715 of warrants with exercise reset provisions,
which are considered freestanding derivative instruments. ASC 815 requires these
warrants to be recorded as liabilities as they are no longer afforded equity
treatment. The derivative liability as of July 31, 2010 and April 30, 2010 of
$14,523,830 and $17,429,787, respectively is comprised of three transactions,
3,000,000 warrants issued in the current and past years, which are subject to an
ongoing litigation matter, 716,715 warrants issued in an equity financing in
March 2010 and 300,000 warrants issued pursuant to a consulting arrangement in
March 2010. The terms of the exercise reset provision on the 716,715 warrants
expire in September 2010, hence the related fair value of this derivative of
$326,950 has been recorded as a current liability. The Company utilized the
Black-Scholes pricing model with the following weighted average assumptions:
risk free rates from 1.47% to 2.42%, expected life terms ranging from .42 years
to 2.5 years, an expected volatility range of 49% to 145% depending on the term
of such equity contracts and a dividend rate of 0.0%. The fair value of the
warrants issued and outstanding at May 1, 2009, attributed to this derivative
liability has been determined to be immaterial due to the low stock price in
comparison to the exercise price, hence there was no adjustment to make upon
adoption of this accounting standard. During the three months ended July 31,
2010, the Company has recorded non-cash gains of $2,905,957 relating to the
change in fair value of these derivative instruments.
Additional Fair Value Language
The accounting guidance establishes a fair value hierarchy based on whether the
market participant assumptions used in determining fair value are obtained from
independent sources (observable inputs) or reflect the Company's own assumptions
of market participant valuation (unobservable inputs). A financial instrument's
categorization within the fair value hierarchy is based upon the lowest level of
input that is significant to the fair value measurement. The accounting guidance
establishes three levels of inputs that may be used to measure fair value:
13
o Level 1--Quoted prices in active markets that are unadjusted and accessible
at the measurement date for identical, unrestricted assets or liabilities;
o Level 2--Quoted prices for identical assets and liabilities in markets that
are inactive; quoted prices for similar assets and liabilities in active
markets or financial instruments for which significant inputs are observable,
either directly or indirectly; or
o Level 3--Prices or valuations that require inputs that are both unobservable
and significant to the fair value measurement.
The Company considers an active market to be one in which transactions for the
asset or liability occur with sufficient frequency and volume to provide pricing
information on an ongoing basis, and views an inactive market as one in which
there are few transactions for the asset or liability, the prices are not
current, or price quotations vary substantially either over time or among market
makers. Where appropriate the Company's or the counterparty's non-performance
risk is considered in determining the fair values of liabilities and assets,
respectively.
The fair value of our financial instruments at July 31, 2010 and April 30, 2010
follows:
Fair Value Measurements at Reporting Date Using
-----------------------------------------------
Quoted
Prices in
Active
Markets Significant
for Other Significant
Identical Observable Unobservable
Assets Inputs Inputs
Description (Level 1) (Level 2) (Level 3)
----------------------- ---------- ----------- ------------
Derivative securities -
April 30, 2010 ........ $ -- $ -- $ 17,429,787
========== =========== ============
Derivative securities -
July 31, 2010 ......... $ -- $ -- $ 14,523,830
========== =========== ============
(7) LONG-TERM DEBT
The Company had the following debt obligations at July 31, 2010 and April 30,
2010:
July 31, April 30,
2010 2010
----------- -----------
6% convertible secured promissory notes, secured by
35,235 lease acreage, bearing interest at 6.00%,
due December 4, 2016 ............................ $ 1,185,000 $ 1,705,000
Secured promissory notes, secured by certain
equipment, bearing interest at 12%, due
November 1, 2013 and December 1, 2013 ........... 3,071,444 2,721,444
----------- -----------
Total Notes Payable .......................... 4,256,444 4,426,444
Less current maturities on other notes payable -- --
Less debt discount ........................... (1,151,700) (1,383,271)
----------- -----------
Notes Payable - Long-term .................... $ 3,104,744 $ 3,043,173
=========== ===========
14
In December 2009, the Company raised $2,855,000 as 6% convertible secured
promissory notes. These convertible secured notes bear interest at 6% per annum
and mature in December 2016. The convertible secured notes, including any
accrued and unpaid interest are convertible into common stock at $.55 per share,
at the option of the holder. The conversion price was below market at the time
of this debt raise, as a result the fair value of beneficial conversion feature
was computed to be $809,263. This beneficial conversion feature was recorded as
a debt discount and is being amortized over the term of the debt. The
amortization expense recorded for the quarter ended July 31, 2010 was $38,710.
On November 1, 2009, December 15, 2009 and May 15, 2010 MEI, a controlled entity
of the Company, extended loans, as amended, of $2,365,174, $356,270, and
$350,000 respectively, totaling $3,071,444 to the Company. These loans bear
interest at a rate of 12% per year and are due in four years. These loans
require monthly payments of interest only, with the principal due at the
maturity date. The Company provided oil and gas drilling equipment as collateral
for the loan. The Company issued 1,329,250 shares of common stock and 1,329,350
warrants to purchase common stock at an exercise price of a $1.00. These common
shares and warrants issued had a fair value of $1,048,765, which have been
recorded as a debt discount to be amortized over 48 months the term of such
debt. Amortization expense of the debt discount costs for the quarter ended July
31, 2010 was $65,548.
ASC 410-20 "Accounting for Asset Retirement Obligations" addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. This
statement requires companies to record the present value of obligations
associated with the retirement of tangible long-lived assets in the period in
which it is incurred. The liability is capitalized as part of the estimated
costs to capitalize a well and site remediation once a well is abandoned. Over
time, accretion of the liability is recognized as an operating expense and the
capitalized cost is depreciated over the expected useful life of the related
asset. The changes in the Company's liability for the periods ended April 30,
2009 and July 31, 2010 are as follows:
Asset retirement obligation as of April 30, 2010 .. $ 15,662,003
Changes for 2011 .................................. -
------------
Asset retirement obligation as of July 31, 2010 ... $ 15,662,003
(8) STOCKHOLDERS' EQUITY
During the three months ended July 31, 2010, we issued the following securities:
1,164,489 shares, which included four warrant holders who exercised warrants for
177,600 shares in a cashless exercise that netted them 142,286 shares and three
other warrant holders exercised warrants for 76,750 shares for an exercise price
of $1.00. In addition, nine note holders converted $520,000 of their 6% secured
convertible notes at a conversion rate of $0.55 and were issued 945,453 shares.
The Company also issued 3,100,000 employee and director options between February
18, 2010 and July 29, 2010 which created compensation expense of $515,891 for
the 3 months ended July 31, 2010.
The Company presents "basic" earnings (loss) per share and, if applicable,
"diluted" earnings per share pursuant to the accounting guidance issued by the
FASB. The calculation of diluted earnings per share is similar to that of basic
earnings per share, except that the denominator is increased to include the
number of additional common shares that would have been outstanding if all
potentially dilutive common shares, such as those issuable upon the exercise of
stock options and warrants, were issued during the period.
As of July 31, 2010 the exercise price of warrants and options below market
value were $10,277,796, and therefore there are dilutive effects of the common
stock equivalents for the outstanding vested stock options and warrants for the
three months ended July 31, 2010.
15
(9) STOCK OPTIONS AND WARRANTS
We record share-based payments at fair value and record compensation expense for
all share-based awards granted, modified, repurchased or cancelled after the
effective date, in accord with FASB guidance for "Share-Based Payments". We
record compensation expense for outstanding awards for which the requisite
service had not been rendered as of the effective date over the remaining
service period.
We estimated the fair value of options and warrants granted during the three
months ended July 31, 2010 and 2009 on the date of grant, using the
Black-Scholes pricing model with the following assumptions:
2010 2009
-------- --------
Weighted average of expected risk-free interest
rates (Approximate 3 year Treasury Bill rate) .... 2.21% 1.49%
Expected years from vest date to exercise date ..... 3.0 2.5
Expected stock volatility .......................... 50-216% 371-391%
Expected dividend yield ............................ 0% 0%
The Company has adopted the FASB guidance, "Share Based Payments" FASB ASC
718-10. This guidance requires companies to expense the value of employee stock
options and similar awards and applies to all outstanding and vested stock-based
awards. In computing the impact, the fair value of each option is estimated on
the date of grant based on the Black-Scholes options-pricing model utilizing
certain assumptions for a risk free interest rate; volatility; and expected
remaining lives of the awards. The assumptions used in calculating the fair
value of share-based payment awards represent management's best estimates, but
these estimates involve inherent uncertainties and the application of management
judgment.
As a result, if factors change and the Company uses different assumptions, the
Company's stock-based compensation expense could be materially different in the
future. In addition, the Company is required to estimate the expected forfeiture
rate and only recognize expense for those shares expected to vest. In estimating
the Company's forfeiture rate, the Company analyzed its historical forfeiture
rate, the remaining lives of unvested options, and the amount of vested options
as a percentage of total options outstanding.
If the Company's actual forfeiture rate is materially different from its
estimate, or if the Company reevaluates the forfeiture rate in the future, the
stock-based compensation expense could be significantly different from what we
have recorded in the current period.
The Company recorded $515,891 and $0 of compensation expense, net of related tax
effects, relative to stock options and warrants for the three months ended July
31, 2010 and 2009, respectively in accordance with the FASB guidance. Net loss
per share basic for this expense is $0.02 and $0.00 and net loss per share
diluted for this expense is $0.01 and $0.00.
The aggregate intrinsic value is calculated as the difference between the
exercise price of the underlying awards and the quoted price of our common stock
for those awards that have an exercise price currently below the closing price.
During the three months ended July 31, 2010 and 2009, the aggregate intrinsic
value of stock options and warrants outstanding was $4,132,221 and $0,
respectively.
16
A summary of the stock options and warrants as of July 31, 2010 and 2009 and
changes during the periods is presented below:
Three months ended Three months ended
July 31, 2010 July 31, 2009
---------------------------- ----------------------------
Number of Weighted Number of Weighted
Options and Average Options and Average
Warrants Exercise Price Warrants Exercise Price
----------- -------------- ----------- --------------
Balance at April 30 12,306,305 $ 1.50 4,090,000 $ 0.88
Granted ........... 325,000 5.13 120,000 1.15
Exercised ......... 219,036 1.29 - -
Expired ........... - - - -
Cancelled ......... 135,314 1.00 - -
----------- -------------- ----------- --------------
Balance at July 31 12,276,955 2.49 4,210,000 0.88
Options exercisable
at July 31 ........ 6,739,455 $ 1.53 3,960,000 $ 0.92
=========== ============== =========== ==============
The following table summarizes information concerning stock options and warrants
outstanding and exercisable at July 31, 2010:
Options and Warrants
Options and Warrants Outstanding Exercisable
---------------------------------------------------- ----------------------
Weighted
Average Weighted Weighted
Range of Remaining Average Average
Exercise Number Contractual Exercise Number Exercise
Price Outstanding Life Price Exercisable Price
------------- ----------- ----------- -------- ----------- --------
$0.01 to 0.69 2,080,000 2.9 $ 0.31 1,892,500 $ 0.31
1.00 to 1.82 4,779,900 3.2 1.08 3,279,900 1.11
2.00 to 2.52 1,750,000 3.9 2.13 750,000 2.30
4.98 to 6.94 3,667,055 17.7 5.74 817,055 5.28
----------- -------- ----------- --------
12,276,955 7.6 $ 2.49 6,739,455 $ 1.53
=========== ======== =========== ========
(10) INCOME TAX
The Company operates several oil and gas wells in Alaska and has leased
properties for other oil and gas exploration purposes. Alaska has investment tax
incentives whereby through June 30, 2010, up to 20% of certain qualified
expenditures are reimbursable via a tax credit which can be sold to other oil
and gas companies at a discount to obtain an immediate realization of such
benefits or such tax credits could be utilized by the Company to offset taxes
due or obtain a refund based on certain future reinvestment criteria. Effective
July 1, 2010, the state of Alaska has increased the tax incentive rate from 20%
to 40% and relaxed the criteria for a refund requirement to be obtained from the
state of Alaska. The Company has recorded a total of $1,603,358 in other assets
for an estimate of an investment tax credit incentive refund due from the state
of Alaska, as of July 31, 2010, of which $496,358 was recorded during the three
months ended July 31, 2010.
17
(11) COMMITMENTS
On August 6, 2008 the Board of Directors employed Scott M. Boruff as CEO of the
Company. The employment contract, as amended, provided for the following
compensation:
o Base salary of $250,000 per annum, with provision for cost-of-living
increases.
o Options to purchase 250,000 shares of the Company's common stock at an
exercise price per share of $0.33, with vesting in equal annual installments
over a period of four years.
o A restricted stock grant of 250,000 shares of common stock, with vesting in
equal annual installments over a period of four years.
o Incentive Compensation - For each year of the employment term, (i) cash up to
100% of base salary and (ii) up to 100,000 shares of restricted common stock,
in both instances based upon, and subject to, two performance benchmarks,
gross revenue and EBITDA. One half of each element of incentive compensation
is earned if the gross revenue benchmark is achieved, and the other half of
each element is earned if the EBITDA benchmark is achieved.
In August 2008 we engaged a broker-dealer and member of FINRA which is a related
party, to assist us in raising capital by means of a private placement of
securities. As initial compensation for their services, we paid the firm a
$25,000 retainer, issued the firm's assigns 250,000 shares of our common stock,
valued at $115,000 and agreed to pay a monthly consulting fee of $5,000. Upon
the successful completion of the private offering we will be obligated to pay
the firm certain cash compensation and issue them up to an additional 150,000
shares of our common stock in amounts to be determined based upon the gross
proceeds received by us from the financing.
On December 10, 2009, the Company appointed Ford F. Graham as Vice-Chairman of
the Board of Directors of Miller and as President of the Company. Mr. Graham
received a signing bonus of $200,000, an annual initial salary of $200,000 and
initial stock warrants to purchase 1,000,000 shares of Company stock which
exercise prices ranging from $0.01 to $2.00. Mr. Graham resigned from these
positions in June, 2010.
On December 10, 2009, the Company appointed David M. Hall as Director of the
Company and Chief Executive Officer of the Company's Alaska subsidiary, Cook
Inlet Energy, LLC. Mr. Hall is compensated at an annual initial salary of
$195,000 and has a three year employment agreement. In addition, the Company
employed Walter J. Wilcox II and Troy Stafford, with three-year employment
agreements to assist Mr. Hall. These gentlemen are currently being compensated
under an oral agreement, however, the Company intends to enter into written
employment agreements in the immediate future under the same terms and
conditions. In May 2010, Mr. Stafford left the employ of Cook Inlet Energy, LLC.
On November 1, 2009 and on December 15, 2009, and May 15, 2010 MEI a controlled
entity of the Company, extended loans, as amended, of $2,365,174 and $356,270
and $350,000, respectively, totaling $3,080,444 to the Company. These loans bear
interest at the rate of 12% per year and are due in four years. These loans
require monthly payments of interest only, with the principal due at the
maturity date. The Company provided oil and gas drilling equipment as collateral
for the loan. The Company issued 1,329,250 shares of common stock and 1,329,350
warrants to purchase common stock at an exercise price of a $1.00. These common
shares and warrants issued had a fair value of $1,048,765, which have been
recorded as a debt discount to be amortized over 48 months the term of such
debt.
18
In addition the Company incurred $619,358 of finance costs of professional fees
and commissions paid to raise such monies for MEI, as a result these monies are
being amortized as deferred financing costs over the term of such debt of 48
months. Amortization expense of the deferred finance costs for the quarter ended
July 31, 2010 was $38,710. Amortization expense of the debt discount costs for
the quarter ended July 31, 2010 was $65,548.
(12) LITIGATION
CNX Gas Company, LLC commenced litigation on June 11, 2008 in the Chancery Court
of Campbell County, State of Tennessee in a case style CNX Gas Company, LLC vs.
Miller Petroleum Inc., Civil Action No. 08-071, to enjoin us from assigning or
conveying certain leases described in the Letter of Intent signed by CNX and our
company on May 30, 2008, to compel us to specifically perform the assignments as
described in the Letter of Intent; and for damages. A Notice of Lien Lis Pendens
was issued June 11, 2008. We moved for entry of summary judgment dismissing the
claims asserted against us by CNX and on January 30, 2009 the court found that
CNX's claims had no merit. The court granted our motion and dismissed all claims
asserted by CNX in that action. CNX has appealed the ruling, and briefs have
been submitted to the Court of Appeals of Tennessee. Oral arguments were held on
May 18, 2010, and an opinion from the Court of Appeals is expected sometime in
the fall of 2010.
On May 20, 2009 Gunsight Holdings, LLC, a Florida limited liability company,
filed a complaint in the United States District Court for the Eastern District
of Tennessee, Northern Division, against us styled Gunsight Holdings, LLC,
Plaintiff, v Miller Petroleum, Inc. and Ky-Tenn Oil, Inc., Defendants, Case No.
3-09-CV-221. The litigation surrounds certain rights related to approximately
6,800 acres in Scott County, Tennessee which KTO purportedly acquired under a
lease assignment from an unrelated party in August 2004. In September 2008, KTO
assigned us 75% of its interest in the subject lease and the working interest in
all the wells on the leased land, retaining a 25% interest in the wells
consisting of landowner's royalty and overriding royalty. On June 8, 2009 we
acquired certain assets from KTO including KTO's undivided interest in
approximately 170 oil and gas wells in Morgan, Scott and Fentress counties in
Tennessee, together with all property, fixtures and improvements, leasehold
interest and contract rights related to these wells and undivided interest in
approximately 35,325 acres of oil and gas leases in Scott and Morgan counties,
Tennessee. The lease which is the subject of the litigation was included in the
assets purchased by us from KTO. The plaintiff is alleging that our company and
KTO have failed or refused to pay royalties due to the plaintiff's predecessors
and have breached the implied duty of further exploration by failing to drill
required wells, failing to reasonably develop or explore the property, failing
to maintain an active interest in further development of the property and
otherwise failing to act as a prudent operator of the property thereby causing
damages to the plaintiff exceeding $75,000. The plaintiff is seeking a
declaratory judgment of its allegations, removal of our company and KTO from the
property, a full accounting of activities related to the property and all monies
received from those activities, damages and costs of action. We have filed an
answer denying the various claims and asserting affirmative defenses including
that there has been continuous production from the subject lease. We are
currently in discovery.
On October 8, 2009 we filed an action styled Miller Petroleum, Inc. v. Maynard,
Civil Action No. 9992 in the Chancery Court for Scott County, Tennessee, seeking
a declaratory judgment that there has been continuing commercial production of
oil, and oil and gas lease owned by us is still in full force and effect. The
defendant filed an Answer and Counterclaim, seeking in the Counterclaim a
declaration that the oil and gas lease has expired. Although no compensatory
monetary damages have been sought against us, the Counterclaim does seek
attorney fees, expenses and costs. There has been no discovery to date and a
trial date has not been assigned. Plaintiff's attorney left his firm, and the
case has been delayed as plaintiff's new counsel (with the same firm) becomes
familiar with the case.
19
On March 26, 2010, Petro Capital III, LP filed an action styled Petro Capital
III, LP v. Miller Petroleum, Inc., Civil Action No. 3:10-cv-00606P in the United
States District Court for the Northern District of Texas, Dallas Division,
seeking damages for breach of contract; damages for alleged negligent
misrepresentation; a declaratory judgment regarding the proper number of and
exercise price of the original warrants to which Petro Capital is entitled under
a warrant and registration rights agreement, the number of penalty warrants to
which Petro Capital may be entitled under a warrant and registration rights
agreement, as well as the proper exercise price thereof, and damages resulting
from the alleged breach of contract; and attorney's fees. On April 6, 2010,
Petro Capital filed an Amended Complaint that did not include additional causes
of action. We filed an Answer and Counterclaim on April 28, 2010. The
Counterclaim seeks a declaratory judgment to declare void the issuance of any
penalty warrants after May 4, 2007 (the latest date upon which the shares
underlying the warrants would become freely tradable under Rule 144). The
Counterclaim further seeks a declaratory judgment as to the number of shares and
proper exercise price for the original warrant.
We are also party to various routine legal proceedings arising in the ordinary
course of our business. Management believes that none of these actions,
individually or in the aggregate, will have a material adverse effect on our
financial condition or results of operations.
(13) SUBSEQUENT EVENTS
In August 2010, two of our note holders converted $25,000 of their 6% secured
convertible notes at a conversion rate of $0.55 and were issued 45,455 shares.
20
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
We are an independent exploration and production company that utilizes seismic
data, and other technologies for geophysical exploration and development of oil
and gas wells in the Appalachian region of eastern Tennessee and the Cook Inlet
Basin in south central Alaska. In addition to our engineering and geological
capabilities, we provide land drilling services on a contract basis to customers
primarily engaged in natural gas exploration and production.
During fiscal 2009 and 2010, we completed several transactions which we believe
had both a positive impact on our balance sheet and will assist us in our
continued growth. These transactions, which are described in detail in our
Annual Report for fiscal year 2010, included the following:
o sale of leases and wells to Atlas Energy Recourses, LLC,
o settlement of Wind City litigation,
o acquisition of assets from Ky-Tenn Oil, Inc. ("KTO"),
o acquisition of East Tennessee Consultants, Inc. ("ETC") and East
Tennessee Consultants, LLC ("LLC"),
o acquisition of Cook Inlet Energy LLC in Alaska, and
o acquisition of Alaskan assets of Pacific Energy Resources.
As a result of these acquisitions, we presently have approximately 634,219 acres
of gross oil and gas leases and exploration license rights (597,224 net acres),
which includes 471,474 acres under the Susitna Basin Exploration License. The
terms of these new leases have a net revenue interest ranging from 0.1% to 100%
and run from three to five years. We are presently reviewing these leases, as
well as our other existing leases, to determine the capital requirements and
timing for drilling additional wells. During the three months ended July 31,
2010, we began reworking two of our Alaska wells and capitalized approximately
$3.9 million of costs associated with those efforts. In addition, we plan to
drill five new wells in the next nine to 12 months. However, this is dependent
upon the availability of additional capital. As a part of our fiscal 2008 sale
to Atlas Energy, we retained a 5% royalty interest on a 1,930 acre tract that we
expect to be the subject of Atlas Energy drilling. With the closing of these
transactions, our management is now focusing the majority of its efforts on
growing our company. In addition to raising capital we are also continuing to
focus our short-term efforts on three distinct areas, including the following:
o continuing to increase our overall oil and gas production through
maintenance and repairs of nonperforming or underperforming wells,
o organically growing production through drilling for our own benefit on
existing leases and under license rights, leveraging our 100,000 plus
well log database and over 600,000 acres which are either under lease
or part of the Susitna Basin Exploration License, with a view towards
retaining the majority of working interest in the new wells, and
o expanding our contract drilling and service capabilities and revenues,
including drilling and service contracts with third parties.
21
Our ability, however, to implement one or more of these goals in a timely manner
is dependent upon the availability of additional capital. To fully expand our
operations as set forth above, we will need up to $75 million to $100 million to
fund the balance of our expansion plans, including up to approximately $67.4
million associated with obligations arising from our purchase of the Alaskan
assets. To provide the required capital, we are seeking to leverage our existing
assets as well as raise additional capital through the sale of equity and/or
debt securities. We do not have any firm commitments for the additional capital
we need to fully fund our operations and there are no assurances the capital
will be available to us upon terms acceptable to us, if at all. While we are
actively seeking to secure the additional capital, terms of the Securities
Purchase Agreement for the March 2010 private offering contains restrictive
covenants which may adversely impact our ability to raise additional capital
until August 2011. If we are not able to raise the capital as required, we will
be unable to fully implement our expanded business model, and the State of
Alaska could terminate the leases which comprise substantially all of our Cook
Inlet Basin assets. We may also be required to reduce overhead until further
capital is obtained.
During the first quarter of fiscal 2011, Cook Inlet Energy was one of nine
successful bidders in State of Alaska's Division of Oil & Gas Cook Inlet
Areawide 2010 Competitive Oil and Gas Lease Sale. There were 38 bids for 36
tracts covering an estimated 144,640 acres of State of Alaska oil and gas
acreage. Cook Inlet Energy bid on seven tracts and was the successful high
bidder on each of those tracts which cover an estimated 27,520 acres. Cook Inlet
Energy's winning bid for these seven tracts was $908,800. Cook Inlet Energy paid
a deposit of $181,767 at the time of the auction and the balance will be due
once the title work is complete which we presently anticipate to be in January
2011. All of Cook Inlet Energy's bids completed acreage positions covering
prospects acquired in its purchase of a portfolio of Pacific Energy Alaska
assets. We have not included this acreage in our calculation of gross or net
lease acres in this report.
On May 25, 2010, Cook Inlet Energy entered into a letter agreement with
Buccaneer Alaska, LLC to assign four leases with a total gross acreage of
8,828.5 acres to Buccaneer Alaska for a total consideration of $12,500.00. The
effective date of the assignment was June 1, 2010. We retained the following
overriding royalty interests in each lease including 2% in the ADL-391108 and
ADL-17595-2 leases and 4% in the ADL-390379 and ADL-390370 leases. If Buccaneer
Alaska fails to drill at least one well on the leased acreage by 2013, we will
be entitled to a payment of $303,613, and may choose to cause Buccaneer Alaska
to assign any of the leases to us that remain active.
LEASES AND LICENSES
During fiscal 2010 our three acquisitions resulted in additional gross leases
and licenses of 642,681 acres and additional net leases and licenses of 596,239
acres bringing the total oil and gas leases and licenses held by us to gross
leases and licenses of 657,170 acres and net leases and licenses of 610,728
acres. After the sale and assignment of leases to Buccaneer Alaska, those
numbers are 634,219 acres (gross) and 597,224 acres (net). We retained
overriding royalty interests ("ORRI") in the acres sold to Buccaneer Alaska, and
hold a total 25,964 acres in ORRIs in Alaska. We do not include the ORRI acreage
in our calculation of leased and licensed acreage. The terms of these new leases
and licenses have a net revenue interest ranging from 0.1% to 100.0% and run
from three to five years. We are presently reviewing these leases, as well as
our other existing leases, and licenses, to determine the capital requirements
and timing for drilling additional wells. To expand our operations by drilling
on these leases, we will require additional capital. As a part of our fiscal
2008 sale to Atlas Energy, we retained a 5% royalty interest on a 1,930 acre
tract that we expect to be the subject of Atlas Energy drilling. When wells are
developed on this acreage, we stand to share in any profit they create.
Additionally, we retained the right to participate in up to ten wells with a 25%
working interest without promote.
22
RESULTS OF OPERATIONS
REVENUES
--------
The following table shows the components of our revenues for the three months
ended July 31, 2010 and 2009, together with their percentages of total revenue
in 2010 and percentage change on a period-over-period basis.
For the Three Months Ended
-------------------------------------------------
July 31, % of July 31, % of
2010 Revenue 2009 Revenue % Change
---------- ------- --------- ------- --------
REVENUES
Oil and gas revenue ........ $4,791,179 92% $ 404,392 77% 1,085%
Service and drilling revenue 409,068 8% 123,228 23% 232%
---------- ---------
Total Revenue .............. $5,200,247 100% $ 527,620 100% 886%
Oil and gas revenue represents revenues generated from the sale of oil and
natural gas produced from the wells in which we have a partial ownership
interest. Oil and gas revenue is recognized as income as production is extracted
and sold. We reported over 1,000% increase in oil and gas revenues for the three
months ended July 31, 2010 over the three months ended July 31, 2009. This
increase was due to the addition of the Alaskan oil well production during
fiscal 2010 which accounted for revenues of approximately $4,656,588 during the
first quarter of fiscal 2011.
At July 31, 2010 oil was priced at $78.85 per barrel versus $69.26 at July 31,
2009 and at July 31, 2010 natural gas was $4.92 per Mcf as compared to $3.65 per
Mcf at July 31, 2009. In addition, we had 186 producing oil wells and 323
producing gas wells on July 31, 2010 compared to 173 producing oil wells and 253
producing gas wells on July 31, 2009. For the three months ended July 31, 2010
we produced 72,788 barrels of oil and 78,700 Mcf of natural gas as compared to
2,449 barrels of oil and 19,131 Mcf of natural gas during the three months ended
July 31, 2009.
Service and drilling revenue represents revenues generated from drilling,
maintenance and repair of third party wells. Service and drilling income is
recognized at the time it is both earned and we have a contractual right to
receive the revenue. Our service and drilling revenue increased 232% for the
three months ended July 31, 2010 as compared to the three months ended July 31,
2009. During the three months ended July 31, 2010 we entered into a contract
with National Park Service for plugging non-company related abandoned wells
located in the Big South Fork area in Tennessee and Kentucky and recorded
$133,445 of revenue. In addition, for the three months ended July 31, 2010, we
record a full quarter's worth of service revenue for our subsidiary, East
Tennessee Consultants, Inc. which resulted in revenue of $157,902 as compared
$65,541 recorded during the three months ended July 31, 2009. East Tennessee
Consultants, Inc. was acquired on June 18, 2009.
23
DIRECT EXPENSES
---------------
The following tables show the components of our direct expenses for the three
months ended July 31, 2010 and 2009. Percentages listed in the table reflect
margins for each component of direct expenses and percentages of total revenue
for each component of other expenses.
For the Three Months Ended
-------------------------------------------
July 31, July 31,
2010 Margin 2009 Margin
---------- ------ --------- ------
DIRECT EXPENSES
Oil and gas ................ $2,304,107 52% $ 24,044 94%
Service and drilling ....... 495,747 (21)% 244,500 (98)%
Depletion expense .......... 1,576,848 n/a 117,434 n/a
---------- ---------
Total direct expenses ...... $4,376,702 16% $ 385,978 27%
We follow the successful efforts method of accounting for our oil and gas
activities. Accordingly, costs associated with the acquisition, drilling and
equipping of successful exploratory wells are capitalized. During the three
months ended July 31, 2010 we capitalized approximately $3,869,738 of costs
associated with the acquisition, drilling and equipping of these wells as
compared to $19,036 during the three months ended July 31, 2009. However,
geological and geophysical costs, delay and surface rentals and drilling costs
of unsuccessful exploratory wells are charged to expense as incurred and are
included in the cost of service and drilling revenue. Finally, costs of drilling
development wells are capitalized. Upon the sale or retirement of oil and gas
properties, the cost thereof and the accumulated depreciation or depletion are
removed from the accounts and any gain or loss is credited or charged to
operations. During the three months ended July 31, 2010, oil and gas expenses
increased $2,280,063 from the three months ended July 31, 2009, which was
primarily due to the dollars we spent to generate oil and gas revenue at our
Alaska operations.
The cost of service and drilling revenue represents direct labor costs of
employees associated with these services, as well as costs associated with
equipment, parts and repairs. During the three months ended July 31, 2010,
service and drilling expenses increased $251,247 from the three months ended
July 31, 2009, which approximately half was due to the costs associated with the
contract with National Park Service for plugging abandoned wells.
Depletion of capitalized costs of proved oil and gas properties is provided on a
pooled basis using the units-of-production method based upon proved reserves.
Acquisition costs of proved properties are amortized by using total estimated
units of proved reserves as the denominator. All other costs are amortized using
total estimated units of proved developed reserves. During the three months
ended July 31, 2010 depletion expense was $1,576,848 or 30% of total revenue, as
compared to 22% for the three months ended July 31, 2009. The primary reason for
the increase in depletion expense for the three months ended July 31, 2010 was
the addition of well production due to acquisitions.
As a result of these components, total direct expenses reflected a margin of 16%
for the three months ended July 31, 2010. This represented a decreased margin of
11% experienced for the three months ended July 31, 2009. As a result of higher
depletion costs, pipeline transportation costs and royalties payable to Alaska,
our gross margins on oil and gas sales from our Alaskan operations will
generally be less than oil and gas sales from our Appalachian operations. Given
that oil and gas sales from our Alaskan operations are expected to represent the
majority of our oil and gas sales in future periods, we anticipate that our
gross margins will be lower than those which were historically reported before
we acquired these assets.
24
OTHER EXPENSES (REVENUES)
-------------------------
The following tables show the components of our other expenses (revenues) for
the three months ended July 31, 2010 and 2009. Percentages listed in the table
reflect percentages of total revenue for each component of other expenses.
For the Three Months Ended
-------------------------------------------
July 31, % of July 31, % of
2010 Revenue 2009 Revenue
----------- ------- --------- -------
OTHER EXPENSES (REVENUES)
Selling, general and administrative $ 2,766,673 53% $ 652,392 124%
Depreciation and amortization ..... 413,824 8% 111,727 21%
Interest expense, net of interest
income ........................... 214,785 4% 4,898 1%
Gain on derivative securities ..... (2,905,957) (56)% -- n/a
Loan fees and costs ............... 90,380 2% 52,636 10%
Gain on sale of property and
equipment ........................ 12,500 0% 9,755 2%
Loss (gain) on acquisitions ....... -- <1% (761,200) (144)%
----------- ---------
Total other expenses (revenues) ... $ 592,205 11% $ 70,208 276%
OTHER EXPENSES (REVENUES)
Selling, general and administrative expense includes salaries, general overhead
expenses, insurance costs, professional fees and consulting fees. The increase
for the three months ended July 31, 2010 as compared to the three months ended
July 31, 2009 primarily reflects the addition of our new Alaska acquisition for
an additional $792,259 in costs for the three months ended July 31, 2010. This
new layer of expense will continue in future quarters and may increase as
further development in Alaska occurs. In addition, $515,891 was booked as
compensation expense during the quarter which reflected the cost of options
issued to employees and directors. This quarterly expense will continue to be
amortized throughout fiscal 2013. Also, the increase included an additional
$291,106 in professional fees due primarily to increased accounting and attorney
fees. In total, accounting and attorney fees increased approximately $150,000
from the three months ended July 31, 2009 to the three months ended July 31,
2010 primarily due to increased work associated with the new acquisitions and
S-1 filing we just completed. In addition, investor relations and public
relations increased approximately $112,000 in this same time period due
primarily to our recent listing on NASDAQ.
Depreciation and amortization expenses reflect the usage of our fixed assets
over time. The increase in depreciation and amortization for the three months
ended July 31, 2010 as compared to the three months ended July 31, 2009 reflects
an increase in the amount of depreciation due to the Alaskan assets purchase.
These non-cash expenses will continue at this higher level as the Alaska assets
are being depreciated over a range of 30 to 40 years.
Interest expense, net of interest income increased $209,887 in the three months
ended July 31, 2010 as compared to the three months ended July 31, 2009
primarily due to interest expense on the long-term debt to a related party as
previously described.
25
Derivative securities liability fluctuates from quarter to quarter based on
changes in the components of the Black-Scholes pricing model including the
Company's ending stock price, risk free rates, expected life terms, expected
volatility and expected dividend rates. During the three months ended July 31,
2010, the Company has recorded non-cash gains of $2,905,957 relating to the
change in fair value of these derivative instruments. The application of this
accounting treatment on our financial statements in future periods could
likewise result in non-cash losses. Accordingly, investors should not place an
undue reliance on these non-cash gains as they are not reflective of our
operating performance.
During the three months ended July 31, 2009, we recorded a loss of $67,545 in
connection with our acquisition of assets from KTO and we recorded a gain of
$828,745 in connection with our acquisitions of ETC and LLC. Therefore, the net
gain for the quarter ended July 31, 2009 was $761,200. This gain and loss were
calculated according to current FASB guidance.
As described earlier in this report, and due primarily to the reasons described
above, during the three months ended July 31, 2010 we recorded net income of
$682,907.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity is the ability of a company to generate adequate amounts of cash to
meet the enterprise's needs for cash. At July 31, 2010 we had a working capital
deficit of $3,019,389 as compared to a working capital surplus of $338,111 at
April 30, 2010. This decrease in capital surplus is primarily due to an increase
in cash related selling, general and administrative expenses for the three
months ended July 31, 2010 of approximately $2,250,000 as well as a $3,869,738
first fiscal quarter investment in oil and gas properties which represents
capital expenditures for the reworking of oil and gas wells in Alaska. As
previously discussed, certain of these general and administrative expenses, such
as the new Alaska general and administrative expenses, will continue and may
even increase in the future as further development occurs.
Net cash provided by operating activities for the three months ended July 31,
2010 period was $1,380,930. This primarily reflects the increase of oil and gas
revenue received in excess of the direct costs of oil and gas revenues paid for
the period. Net cash used by operating activities for the quarter ended July 31,
2009 period was $369,801. This primarily reflects the cash paid for the costs of
revenues and selling, general and administrative expense in excess of revenues
received for the quarter.
Net cash used by investing activities for the three months ended July 31, 2010
of $4,040,766 is primarily due to the $3,869,738 first fiscal quarter capital
expenditures to rework wells we acquired in January 2010. Net cash provided by
investing activities for the quarter ended July 31, 2009 of $30,996 reflects the
net cash we received from the sale of equipment and oil and gas properties,
partially offset by the purchase of additional equipment and oil and gas
properties.
Net cash provided by financing activities of $381,538 for the three months ended
July 31, 2010 primarily reflects $350,000 in proceeds from borrowing on May 15,
2010 from MEI as previously discussed. Net cash provided by financing activities
of $392,257 for the quarter ended July 31, 2009 primarily reflects cash received
from the proceeds of borrowings of $235,266, sale of stock of $119,000 and cash
acquired through acquisitions of $203,993 and were partially offset by the
increase in restricted cash non-current of $166,372 due to the acquisitions.
26
Under the terms of our March 2010 private offering we were required to file a
registration statement with the SEC registering for resale the shares of common
stock sold in the offering, including those underlying the warrants included in
the units, by April 15, 2010. We also agreed to use our best efforts to cause
the registration statement to be declared effective by the SEC within 90 days
from the filing date or 120 days if the registration statement should be
selected for a full review by the staff of the SEC.The registration rights
agreement provides that if we failed to timely file the registration statement,
or if it should not be declared effective within the prescribed time, we are
subject to liquidated damages payable in cash equal to 2% of the aggregate
purchase price of the securities up to a maximum of 12% of the total proceeds of
the offering.
While the registration statement was declared effective by the SEC on August 25,
2010, we did not timely file the registration statement. Because our failure to
timely file the registration statement, during the fourth quarter of fiscal 2010
we accrued registration rights penalties of $602,040 which is payable in cash to
the investors in that offering. Because the registration statement was declared
effective on August 25, 2010, the penalties ceased accruing on that date;
however, we have accrued $602,040 in penalties which is included in our accounts
payable - trade. This amount remains outstanding and the payment of these
penalties will adversely impact our working capital in future periods.
We do not presently have any commitment for capital expenditures other than
related to the Osprey platform and onshore assets as described below. However,
as set forth earlier in this section we require a substantial amount of capital
to fund our other obligations associated with the acquisition of the Alaskan
assets.
Under the terms of the purchase agreement for the Alaskan assets and the
Assignment Oversight Agreement, Cook Inlet Energy assumed all liabilities
related to the plugging, abandonment, decommissioning, removal and/or
restoration liabilities associated with or arising from the acquired assets with
respect to all periods prior to, on or after the closing date. Under the terms
of the purchase agreement for the Alaskan assets, these assumed liabilities
include approximately $10 million for the onshore assets and approximately $40
million associated with a retirement liability for the Osprey platform, of which
approximately $6.6 million is presently on deposit in an escrow fund with the
State of Alaska. We are presently in discussion with the State of Alaska to
reduce these amounts to levels we believe are more realistic. During the fourth
quarter of 2010 we accrued approximately $15.0 million for these liabilities,
which includes approximately $3.5 million for the onshore assets and
approximately $10.0 million for the Osprey platform. We are also seeking to
obtain confirmation from the State of Alaska that the $6.6 million, currently in
the escrow account is specifically allocated to the Osprey platform.
In addition, our long-term cash flows are subject to a number of variables
including the level of production and prices as well as various economic
conditions that have historically affected the oil and gas business. A material
increase in oil and gas prices has recently increased our potential liquidity.
At July 31, 2010 oil was priced at $78.85 per barrel versus $69.26 at July 31,
2009 and at July 31, 2010 natural gas was $4.92 per Mcf as compared to $3.65 per
Mcf at July 31, 2009.
However, a reduction in production and reserves would reduce our operating
results in future periods. We operate in an environment with numerous financial
and operating risks, including, but not limited to, the inherent risks of the
search for, development and production of oil and gas, the ability to buy
properties and sell production at prices which provide an attractive return and
the highly competitive nature of the industry. While we do not anticipate a
worst case scenario, if we are not successful in securing new capital and the
price of oil and gas does not rise significantly and if we were unable to secure
more drilling and servicing contracts, we would need to consider reducing
overhead in an attempt to achieve an operating profit, based on the revenue of
our existing producing oil and gas wells.
27
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable to a smaller reporting company.
ITEM 4. CONTROLS AND PROCEDURES.
Disclosure Controls and Procedures. Under the supervision and with the
participation of our management, including our Chief Executive Officer and our
Chief Financial Officer, we conducted an evaluation of the effectiveness of the
design and operation of our disclosure controls and procedures, as defined in
Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, at the
end of the period covered by this report (the "Evaluation Date"). During fiscal
2010 we failed to timely file with the SEC several Current Reports on Form 8-K.
In an effort to remediate these weaknesses, during the fourth quarter of 2010 we
filled the position of a General Counsel. The General Counsel has developed
systems which should ensure that the information required to be disclosed in our
reports under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods prescribed by SEC rules and
regulations, and that such information is accumulated and communicated to our
management to allow timely decisions regarding required disclosure. As a result
of these remediation efforts, as of the Evaluation Date, our Chief Executive
Officer and Chief Financial Officer, concluded that we maintain disclosure
controls and procedures that are effective in providing reasonable assurance
that information required to be disclosed in our reports under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods prescribed by SEC rules and regulations, and that such information
is accumulated and communicated to our management to allow timely decisions
regarding required disclosure.
Our management, including the Chief Executive Officer and Chief Financial
Officer, does not expect that our disclosure controls and procedures will
prevent all error and all fraud. A control system, no matter how well designed
and operated, can provide only reasonable, not absolute, assurance that the
control system's objectives will be met. Further, the design of a control system
must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any, have
been detected. These inherent limitations include the realities that judgments
in decision-making can be faulty, and that breakdowns can occur because of
simple error or mistake. The design of any system of controls is based in part
upon certain assumptions about the likelihood of future events, and there can be
no assurance that any design will succeed in achieving its stated goals under
all potential future conditions.
Changes in Internal Control Over Financial Reporting. There was no change in our
internal control over financial reporting during our last fiscal quarter that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
We are party to various routine legal proceedings arising in the ordinary course
of our business. Management believes that none of these actions, individually or
in the aggregate, will have a material adverse effect on our financial condition
or results of operations.
ITEM 1A. RISK FACTORS.
Not applicable to a smaller reporting company.
28
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
None
ITEM 4. (REMOVED AND RESERVED).
ITEM 5. OTHER INFORMATION.
On August 27, 2010, we entered into a consulting arrangement with one of our
directors, David J. Voyticky, to locate strategic investments and business
oportunities. Director Voyticky was replaced on the Audit Committee with
Director Gross prior to the entry into the arrangement. A consulting agreement
is being negotiated, and at this time we have reached agreement regarding the
reimbursement of expenses, and the monthly maximum that may be invoiced by Mr.
Voyticky. Mr. Voyticky shall not earn more than a total of $20,000 a month under
the terms of the arrangement.
On May 15, 2010 we borrowed an additional $350,000 from MEI and issued it a
third four year Secured Promissory Note which also pays interest at the rate of
12% per annum with principal and interest payments due monthly. This note is
secured by the same collateral and under the same terms as the First and Second
Promissory Notes issued to MEI.
In connection with these loans, we granted MEI a first position security
interest in oil and gas drilling equipment owned by us. Pursuant to the terms of
an Escrow Agreement, a third-party escrow agent has been retained to hold the
certificates of title for the equipment to which title is evidenced by a
certificate. The remaining equipment is subject to a financing statement that
has been filed with the Tennessee Secretary of State.
We used the proceeds from this loan for general corporate purposes.
The description of the terms and conditions of the Secured Promissory Notes, the
Loan and Security Agreement and the Escrow Agreement do not purport to be
complete and are qualified in their entirety by reference to the full text of
such documents which were filed as Exhibits 10.1, 10.2, 10.3 and 10.4 to our
Quarterly Report on Form 10-Q for the period ended January 31, 2010, and Exhibit
10.34 to our Registration Statement on Form S-1 filed on August 13, 2010.
ITEM 6. EXHIBITS.
31.1 Rule 13a-14(a)/15d-14(a) certificate of Chief Executive Officer 2002
31.2 Rule 13a-14(a)/15d-14(a) certificate of Chief Financial Officer
32.1 Section 1350 certification of Chief Executive Officer
32.2 Section 1350 certification of Chief Financial Officer
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
MILLER PETROLEUM, INC.
Date: September 13, 2010 By: /s/ Scott M. Boruff
-------------------
Scott M. Boruff
Chief Executive Officer,
principal executive officer
Date: September 13, 2010 By: /s/ Paul W. Boyd
----------------
Paul W. Boyd
Chief Financial Officer, principal
financial and accounting officer
30