EARTHSTONE ENERGY INC - Quarter Report: 2011 September (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|
þ
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QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Quarterly Period Ended September 30, 2011
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o
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number: 0-7914
(Exact Name of Registrant as Specified in its Charter)
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Delaware
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84-0592823
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|
| (State of Incorporation or Organization) |
(I.R.S. Employer Identification No.)
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| 633 17th Street, Suite 1900, Denver, Colorado | 80202-3619 | |
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(Address of principal executive office)
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(Zip Code)
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(303) 296-3076
(Registrant’s telephone number, including area code)
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||
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 the 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | o | Accelerated filer | o |
| Non-accelerated filer | o (Do not check if a smaller reporting company) | Smaller reporting company | þ |
Check whether the issuer is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Shares of common stock outstanding on November 7, 2011: 1,706,756
EARTHSTONE ENERGY, INC.
FORM 10-Q
INDEX
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PART I. FINANCIAL INFORMATION
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Page
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|
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Item 1.
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Financial Statements
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4
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Condensed Consolidated Balance Sheets:
|
||
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September 30, 2011 (Unaudited) and March 31, 2011
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4
|
|
|
Condensed Consolidated Statements of Operations:
|
||
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Three and Six Months Ended September 30, 2011 and 2010 (Unaudited)
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6
|
|
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Condensed Consolidated Statements of Cash Flows:
|
||
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Six Months Ended September 30, 2011 and 2010 (Unaudited)
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7
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|
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Notes to Unaudited Condensed Consolidated Financial Statements:
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||
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September 30, 2011
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8
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|
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Item 2.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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11
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Item 3.
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Quantitative and Qualitative Disclosures About Market Risk
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16
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Item 4.
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Controls and Procedures
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17
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PART II. OTHER INFORMATION
|
||
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Item 1.
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Legal Proceedings
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18
|
|
Item 1A.
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Risk Factors
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18
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Item 2.
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Unregistered Sales of Equity Securities and Use of Proceeds
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18
|
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Item 3.
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Defaults Upon Senior Securities
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18
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Item 4.
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Submission of Matters to a Vote of Security Holders
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18
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Item 5.
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Other Information
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18
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Item 6.
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Exhibits
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19
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Signatures
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20
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2
FORWARD-LOOKING STATEMENTS
This Current Report on Form 10-Q, including information incorporated herein by reference, contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs, assumptions and information currently available to management. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "predict," "plan," "should," "likely," "may," "will," "continue" or similar expressions are intended to identify such statements. All statements other than statements of historical facts that address activities that we anticipate will or may occur in the future are forward-looking statements. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. Forward-looking statements relate to, among other things:
• our strategies, either existing or anticipated;
• our future financial position, including anticipated liquidity;
• our ability to satisfy obligations from cash generated from operations;
• amounts and nature of future capital expenditures, including future share repurchases;
• acquisitions and other business opportunities;
• operating costs and other expenses, including asset retirement obligation expense;
• wells expected to be drilled, other anticipated exploration efforts and associated expenses;
• estimates of proved oil and natural gas reserves, deferred tax assets, and depletion rates;
• our ability to meet additional acreage, seismic and/or drilling cost requirements;
• other estimates and assumptions we use in our accounting policies.
Factors that could cause actual results to differ materially from our expectations include, among others, such things as:
• loss of senior management or technical personnel;
• oil and natural gas prices and production costs;
• our ability to replace oil and natural gas reserves including changes in reserve estimates resulting from expected oil and gas prices, production rates, tax rates and production costs;
• exploitation, development, production and exploration results; including mechanical failure;
• the estimated costs of asset retirement obligation, including whether or not those retirements costs, in whole or in part, are ever actually incurred in the future;
• the potential unavailability of drilling rigs and other field equipment and services;
• the existence of unanticipated liabilities relating to existing properties or those acquired in the future, including environmental liabilities;
• factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment;
• the willingness and ability of third parties to honor their contractual commitments;
• permitting issues;
• the nature, extent and duration of workovers;
• the impact and costs related to compliance with or changes in laws governing our operations;
• acquisitions and other business opportunities (or the lack thereof) that may be pursued by us;
• competition for properties and the effect of such competition on the price of those properties;
• economic, market or business conditions; including any change in interest rates or inflation;
• the lack of available capital and financing;
• risk factors consistent with comparable companies within our industry, especially companies with similar market capitalization and/or employee census;
• weather, and other factors, many of which are beyond our control.
Furthermore, forward-looking statements are made based on our current assessment available at the time. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to our expectations and intentions and, thus, we may alter our plans regarding any exploration and development activities.
Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. As with comparable companies within our industry, there are numerous factors that could cause actual results to differ materially from our expectations. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.
3
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Earthstone Energy, Inc.
Condensed Consolidated Balance Sheets
Page 1 of 2
|
September 30,
|
March 31,
|
|||||||
|
2011
|
2011
|
|||||||
|
(Unaudited)
|
||||||||
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ASSETS
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||||||||
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Current assets:
|
||||||||
|
Cash and cash equivalents
|
$
|
3,137,000
|
$
|
4,051,000
|
||||
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Accounts receivable:
|
||||||||
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Oil and gas sales
|
1,400,000
|
1,674,000
|
||||||
|
Joint interest and other receivables, net of allowance of $93,000 and $86,000, respectively
|
402,000
|
329,000
|
||||||
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Other current assets
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541,000
|
539,000
|
||||||
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Total current assets
|
5,480,000
|
6,593,000
|
||||||
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Oil and gas property, full cost method:
|
||||||||
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Proved property
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35,320,000
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35,379,000
|
||||||
|
Unproved property
|
6,522,000
|
3,112,000
|
||||||
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Accumulated depletion and impairment
|
(25,115,000
|
)
|
(24,713,000
|
)
|
||||
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Net oil and gas property
|
16,727,000
|
13,778,000
|
||||||
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Support equipment and other non-current assets, net of accumulated depreciation of $396,000 and $377,000, respectively
|
498,000
|
471,000
|
||||||
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Total non-current assets
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17,225,000
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14,249,000
|
||||||
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Total assets
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$
|
22,705,000
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$
|
20,842,000
|
||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
4
Earthstone Energy, Inc.
Condensed Consolidated Balance Sheets
Page 2 of 2
|
September 30,
|
March 31,
|
|||||||
|
2011
|
2011
|
|||||||
|
(Unaudited)
|
||||||||
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LIABILITIES AND SHAREHOLDERS’ EQUITY
|
||||||||
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Current liabilities:
|
||||||||
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Accounts payable
|
$
|
188,000
|
$
|
496,000
|
||||
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Accrued liabilities
|
1,864,000
|
1,167,000
|
||||||
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Total current liabilities
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2,052,000
|
1,663,000
|
||||||
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Long-term liabilities:
|
||||||||
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Deferred tax liability
|
2,544,000
|
2,319,000
|
||||||
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Asset retirement obligation
|
1,691,000
|
1,795,000
|
||||||
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Total long-term liabilities
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4,235,000
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4,114,000
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||||||
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Commitments
|
||||||||
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Total liabilities
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6,287,000
|
5,777,000
|
||||||
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Shareholders’ Equity:
|
||||||||
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Preferred shares, $0.001 par value, 600,000 authorized and
none issued or outstanding
|
—
|
—
|
||||||
|
Common shares, $0.001 par value, 6,400,000 shares authorized and
1,788,000 and 1,782,000 shares issued, respectively
|
18,000
|
18,000
|
||||||
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Additional paid-in capital
|
23,064,000
|
23,020,000
|
||||||
|
Treasury stock, at cost, 82,000 and 76,000 shares, respectively
|
(457,000
|
)
|
(373,000
|
)
|
||||
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Accumulated deficit
|
(6,207,000
|
)
|
(7,600,000
|
)
|
||||
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Total shareholders’ equity
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16,418,000
|
15,065,000
|
||||||
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Total liabilities and shareholders’ equity
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$
|
22,705,000
|
$
|
20,842,000
|
||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
5
Earthstone Energy, Inc.
Condensed Consolidated Statements of Operations
(Unaudited)
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
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September 30,
|
September 30,
|
|||||||||||||||
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2011
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2010
|
2011
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2010
|
|||||||||||||
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Revenues:
|
||||||||||||||||
|
Oil and gas sales
|
$
|
2,505,000
|
$
|
1,970,000
|
$
|
4,985,000
|
$
|
3,733,000
|
||||||||
|
Well service and water disposal revenue
|
40,000
|
27,000
|
85,000
|
28,000
|
||||||||||||
|
Total revenues
|
2,545,000
|
1,997,000
|
5,070,000
|
3,761,000
|
||||||||||||
|
Expenses:
|
||||||||||||||||
|
Oil and gas production
|
826,000
|
617,000
|
1,621,000
|
1,118,000
|
||||||||||||
|
Production tax
|
200,000
|
147,000
|
338,000
|
273,000
|
||||||||||||
|
Well service and water disposal
|
—
|
—
|
6,000
|
3,000
|
||||||||||||
|
Depletion and depreciation
|
229,000
|
309,000
|
425,000
|
568,000
|
||||||||||||
|
Accretion of asset retirement obligation
|
41,000
|
41,000
|
82,000
|
81,000
|
||||||||||||
|
General and administrative
|
507,000
|
330,000
|
949,000
|
721,000
|
||||||||||||
|
Total expenses
|
1,803,000
|
1,444,000
|
3,421,000
|
2,764,000
|
||||||||||||
|
Income from operations
|
742,000
|
553,000
|
1,649,000
|
997,000
|
||||||||||||
|
Other income (expense):
|
||||||||||||||||
|
Interest and other income
|
60,000
|
5,000
|
67,000
|
8,000
|
||||||||||||
|
Interest and other expenses
|
―
|
―
|
(3,000
|
)
|
―
|
|||||||||||
|
Total other income, net
|
60,000
|
5,000
|
64,000
|
8,000
|
||||||||||||
|
Income before income tax
|
802,000
|
558,000
|
1,713,000
|
1,005,000
|
||||||||||||
|
Current income tax expense
|
32,000
|
31,000
|
95,000
|
99,000
|
||||||||||||
|
Deferred income tax expense (benefit)
|
42,000
|
(197,000
|
)
|
225,000
|
(196,000
|
)
|
||||||||||
|
Total income tax expense (benefit)
|
74,000
|
(166,000
|
)
|
320,000
|
(97,000
|
)
|
||||||||||
|
Net income
|
$
|
728,000
|
$
|
724,000
|
$
|
1,393,000
|
$
|
1,102,000
|
||||||||
|
Per share amounts:
|
||||||||||||||||
|
Basic
|
$
|
0.43
|
$
|
0.43
|
$
|
0.81
|
$
|
0.65
|
||||||||
|
Diluted
|
$
|
0.43
|
$
|
0.43
|
$
|
0.81
|
$
|
0.65
|
||||||||
|
Weighted average common shares outstanding:
|
||||||||||||||||
|
Basic
|
1,710,804
|
1,683,937
|
1,711,768
|
1,685,352
|
||||||||||||
|
Diluted
|
1,710,804
|
1,699,857
|
1,711,768
|
1,701,272
|
||||||||||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
6
Earthstone Energy, Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
|
Six Months Ended
|
||||||||
|
September 30,
|
||||||||
|
2011
|
2010
|
|||||||
|
Cash flows from operating activities:
|
||||||||
|
Net income
|
$
|
1,393,000
|
$
|
1,102,000
|
||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||
|
Depletion and depreciation
|
425,000
|
568,000
|
||||||
|
Deferred income tax expense (benefit)
|
225,000
|
(196,000
|
)
|
|||||
|
Accretion of asset retirement obligation
|
82,000
|
81,000
|
||||||
|
Payments on asset retirement obligation
|
―
|
17,000
|
||||||
|
Share-based compensation
|
44,000
|
38,000
|
||||||
|
Change in:
|
||||||||
|
Accounts receivable, net
|
201,000
|
|
12,000
|
|||||
|
Other current assets
|
30,000
|
135,000
|
||||||
|
Accounts payable, accrued and other liabilities
|
(205,000
|
)
|
9,000
|
|||||
|
Net cash provided by operating activities
|
2,195,000
|
1,749,000
|
||||||
|
Cash flows from investing activities:
|
||||||||
|
Oil and gas property
|
(2,975,000
|
)
|
(1,780,000
|
)
|
||||
|
Support equipment and other non-current assets
|
(50,000
|
)
|
4,000
|
|
||||
|
Net cash used in investing activities
|
(3,025,000
|
)
|
(1,776,000
|
)
|
||||
|
Cash flows from financing activities:
|
||||||||
|
Purchase of treasury shares
|
(84,000
|
)
|
(79,000
|
)
|
||||
|
|
||||||||
|
Net cash used in financing activities
|
(84,000
|
)
|
(79,000
|
)
|
||||
|
Cash and cash equivalents:
|
||||||||
|
Net decrease in cash and cash equivalents
|
(914,000
|
)
|
(106,000
|
)
|
||||
|
Cash and cash equivalents, beginning of year
|
4,051,000
|
4,905,000
|
||||||
|
Cash and cash equivalents, end of period
|
$
|
3,137,000
|
$
|
4,799,000
|
||||
|
Supplemental disclosure of cash flow information:
|
||||||||
|
Cash paid for interest
|
$
|
―
|
$
|
―
|
||||
|
Cash paid for income tax
|
$
|
1,000
|
$
|
135,000
|
||||
|
Non-cash:
|
||||||||
|
Increase in oil and gas property due to asset retirement obligation
|
$
|
23,000
|
$
|
191,000
|
||||
|
Accrued capital expenditures
|
$
|
719,000
|
$
|
135,000
|
||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
7
Earthstone Energy, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
September 30, 2011
1. Basis of Presentation
The accompanying interim financial statements of Earthstone Energy, Inc. (formerly Basic Earth Science Systems, Inc. sometimes referred to as “the Company” “we” “our” or “us”) are unaudited. However, in the opinion of management, the interim data includes any applicable adjustments necessary for a fair presentation of the financial and operational results for the interim period according to generally accepted accounting principles in the United States of America (“U.S. GAAP”).
At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout the notes to the condensed consolidated financial statements, they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
The financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in financial statements prepared in accordance with U.S. 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 suggest that these financial statements be read in conjunction with the financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended March 31, 2011.
We determined that there were no subsequent events to recognize or disclose in these condensed consolidated financial statements which would either impact the results reflected in this report or the Company’s results going forward.
The results of operations for the three and six months ended September 30, 2011, are not necessarily indicative of the operating results that may be expected for the year ending March 31, 2012.
Fair Value Measurements. The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments.
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.
Commitments. As of September 30, 2011, the Company is committed to a total of $114,000 plus maintenance fees for a lease ending April 30, 2013 on a newly expanded 6,200 square foot office space located in downtown Denver, Colorado. The Company does not have any off-balance sheet financing transactions, arrangements or obligations.
8
2. Accrued Liabilities
|
September 30,
2011 |
|
March 31,
2011 |
||||||
|
(Unaudited)
|
|
|||||||
|
Revenue and production taxes payable
|
$
|
416,000
|
|
$
|
340,000
|
|||
|
Accrued compensation
|
321,000
|
|
223,000
|
|||||
|
Accrued operations payable
|
852,000
|
|
239,000
|
|||||
|
Accrued income tax payable and other
|
144,000
|
238,000
|
||||||
|
Short term asset retirement obligation
|
131,000
|
|
127,000
|
|||||
|
|
||||||||
|
Total accrued liabilities
|
$
|
1,864,000
|
|
$
|
1,167,000
|
|||
|
Three Months Ended
September 30,
|
Six Months Ended
September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(Unaudited)
|
(Unaudited)
|
(Unaudited)
|
(Unaudited)
|
|||||||||||||
|
|
||||||||||||||||
|
Number of treasury shares purchased
|
6,156
|
2,509
|
6,156
|
7,318
|
||||||||||||
|
Total cost
|
$
|
84,000
|
$
|
28,000
|
$
|
84,000
|
$
|
79,000
|
||||||||
|
Average per share cost
|
$
|
13.65
|
$
|
10.68
|
$
|
13.65
|
$
|
10.38
|
||||||||
Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. References to the number of treasury shares and per share amounts reflect the reverse stock split.
4. Income Tax
The provision for income tax for the three and six months ended September 30, 2011 and 2010 is comprised of:
|
Three Months Ended
September 30,
|
Six Months Ended
September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(Unaudited)
|
(Unaudited)
|
(Unaudited)
|
(Unaudited)
|
|||||||||||||
|
Current:
|
||||||||||||||||
|
Federal
|
$
|
29,000
|
$
|
30,000
|
$
|
85,000
|
$
|
91,000
|
||||||||
|
State
|
3,000
|
1,000
|
10,000
|
8,000
|
||||||||||||
|
Total current income tax expense
|
32,000
|
31,000
|
95,000
|
99,000
|
||||||||||||
|
Deferred:
|
||||||||||||||||
|
Federal
|
40,000
|
(14,000
|
)
|
210,000
|
(13,000
|
)
|
||||||||||
|
State
|
2,000
|
(183,000
|
)
|
15,000
|
(183,000
|
)
|
||||||||||
|
Total deferred income tax expense (benefit)
|
42,000
|
(197,000
|
)
|
225,000
|
(196,000
|
)
|
||||||||||
|
Income tax expense (benefit)
|
$
|
74,000
|
$
|
(166,000
|
)
|
$
|
320,000
|
$
|
(97,000
|
)
|
||||||
9
A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the three and six months ended September 30, 2011 and 2010 follows:
|
Three Months Ended
September 30,
|
Six Months Ended
September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(Unaudited)
|
(Unaudited)
|
(Unaudited)
|
(Unaudited)
|
|||||||||||||
|
Federal tax at statutory rate
|
$ | 273,000 | $ | 342,000 | $ | 583,000 | $ | 190,000 | ||||||||
|
State taxes, net of federal benefit
|
11,000 | 25,000 | 28,000 | 18,000 | ||||||||||||
|
Excess percentage depletion
|
(125,000 | ) | (181,000 | ) | (208,000 | ) | (122,000 | ) | ||||||||
|
Other adjustments, net
|
(85,000 | ) | (20,000 | ) | (83,000 | ) | 11,000 | |||||||||
|
Income tax expense (benefit)
|
$ | 74,000 | $ | (166,000 | ) | $ | 320,000 | $ | (97,000 | ) | ||||||
|
Effective rate expressed as a percentage of income before income tax
|
9.2 | % | (9.7 | ) % | 18.7 | % | (29.7 | ) % | ||||||||
The overall effective tax rate expressed as a percentage of book income before income tax for the three and six months ended September 30, 2011, as compared to the same period in 2010, was higher due to the Company having lower deductions related to statutory depletion available in the current period in addition to deferred tax benefits in the three and six months ended September 30, 2010 having true-up adjustments from amounts originally estimated on the prior year tax provision.
Net income tax payments were $1,000 and $135,000 for the six months ended September 30, 2011 and 2010, respectively.
Net deferred tax assets and liabilities as of September 30, 2011 and March 31, 2011 were comprised of:
|
September 30,
|
March 31,
|
|||||||
|
2011
|
2011
|
|||||||
|
(Unaudited)
|
||||||||
|
Deferred tax assets:
|
||||||||
|
Allowance for doubtful accounts
|
$
|
34,000
|
$
|
34,000
|
||||
|
Asset retirement obligation
|
665,000
|
703,000
|
||||||
|
Statutory depletion carry-forward
|
1,247,000
|
1,110,000
|
||||||
|
Gross deferred tax assets
|
1,946,000
|
1,847,000
|
||||||
|
Other accruals
|
32,000
|
69,000
|
||||||
|
Depletion, depreciation and intangible drilling costs
|
(4,522,000
|
)
|
(4,235,000
|
)
|
||||
|
Gross deferred tax liabilities
|
(4,490,000
|
)
|
(4,166,000
|
)
|
||||
|
Deferred tax liabilities, net
|
$
|
(2,544,000
|
)
|
$
|
(2,319,000
|
)
|
||
Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred tax assets and liabilities are continually re-evaluated and numerous estimates are revised over time. As such, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.
The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are the years ended March 31, 2007 through 2011.
10
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended March 31, 2011, as well as the unaudited condensed consolidated financial statements and related notes and other information appearing in Item 1 of this report.
The preparation of our unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the reported amounts in our unaudited condensed consolidated financial statements and the accompanying notes including matters arising during the normal course of business. We apply our best judgment, our knowledge of existing facts and circumstances and our knowledge of actions that we may undertake in the future in determining the estimates that will affect our unaudited condensed consolidated financial statements. We evaluate our estimates on an ongoing basis using our historical experience, as well as other factors we believe appropriate under the circumstances, such as current economic conditions, and adjust or revise our estimates as circumstances change. As future events and their effects cannot be determined with precision, actual results may differ from these estimates.
As used in this report, unless the context otherwise indicates, references to “we,” “our,” “ours,” and “us” refer to Earthstone Energy, Inc. and its subsidiary collectively.
As an oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially and adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is to a large extent determined by factors beyond our control.
Liquidity and Capital Resources
Liquidity Outlook. Our primary source of funding is the net cash flow from the sale of our oil and natural gas production. The profitability and cash flow generated by our operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, we believe the cash generated from operations, along with existing cash balances, should enable us to meet our existing and normal recurring obligations during the next year and beyond.
Overview of our Capital Structure. We recognize the importance of developing our capital resource base in order to pursue our objectives. However, subsequent to our last public offering in 1980, debt financing has been the sole source of external funding. In addition to our routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, we require capital to fund our exploratory and development drilling efforts and the acquisition of additional properties as well as the enhancement of held and newly acquired properties.
11
We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions or debt instruments. Given strong cash flows, and the relatively modest nature of our current drilling projects, we have thus far declined these overtures. Our primary concern in this area is the dilution of our existing shareholders. However, going forward, given that one of the key components of our growth strategy is to expand our oil and natural gas reserve base through drilling and/or acquisitions, if we were presented with a significant opportunity, it is possible we would consider alternative forms of additional financing.
Hedging. During the six months ended September 30, 2011 and 2010, we did not participate in any hedging activities, nor did we have any open futures or option contracts.
Working Capital. At September 30, 2011, we had a working capital surplus of $3,428,000 (a current ratio of 2.67:1) compared to a working capital surplus at March 31, 2011 of $4,930,000 (a current ratio of 3.96:1). The decrease in current ratio is largely a result of the use of cash for drilling and completion costs offset by income from operations.
Cash Flow. The amounts presented herein are presented on a cash basis (or GAAP presentation), and as such may not be consistent with the changes in amounts presented on the Condensed Consolidated Balance Sheets under operating activities and investing activities for expenditures on oil and gas property, which are presented on an accrual basis.
Net cash provided by operating activities was $2,203,000 for the six months ended September 30, 2011, compared to $1,749,000 for the six months ended September 30, 2010. Changes in operating cash relate largely to the $155,000 increase in net income adjusted for non-cash expenses for the six months ended September 30, 2011 compared to the same period ended September 30, 2010. The fluctuation in deferred income tax expense, the timing and payment of accounts payable and accrued liabilities, especially pertaining to capital expenditure outlays, in addition to the timing and collection of accounts receivable and the application of prepaid balances were also factors in deriving net cash flows from operations.
Net cash used in investing activities was 71% higher for the six months ended September 30, 2011, at $3,033,000, than $1,776,000 for the six months ended September 30, 2010. Spending relates primarily to our drilling and completion activities explained in “Capital Expenditures” below. On an accrual basis, we capitalized $3,351,000 of costs for the six months ended September 30, 2011, compared to $1,153,000 for the six months ended September 30, 2010. The timing of payments for these expenditures and those accrued at the respective prior year end is reflected in net cash used in investing activities for the respective six month periods.
Net cash used in financing activities was $84,000 for the six months ended September 30, 2011, and $79,000 for the six months ended September 30, 2011, for the purchase of treasury shares.
Capital Expenditures
The amounts presented herein are presented on an accrual basis, and as such may not be consistent with the amounts presented on the Condensed Consolidated Statement of Cash Flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.
During the six months ended September 30, 2011, we spent $3,516,000 on various projects. This compares to $1,150,000 for the six months ended September 30, 2010. During the six months ended September 30, 2011, 99% of our capital expenditures were dedicated to drilling and completions, with leasehold and acquisitions requiring only 1% of our capital expenditure funds. We spent $2,993,000 (89%) of our funds completing six wells in North Dakota that reached production by quarter-end, developing six wells in the Williston Basin in the completion stage as of quarter-end, and drilling two additional Bakken wells. The remaining $523,000 of capital spending was allocated primarily to improvements to a number of wells, including planned enhancements on four producing wells purchased in December 2010. All projects were funded entirely with internally generated cash flow.
12
As of September 30, 2011, we have outstanding Authorizations for Expenditure (“AFEs”) above our recorded costs totaling $975,000 for our share in un-incurred drilling and completion costs of the wells mentioned above. At present cash flow levels, we expect to have sufficient funds available for our share of both the outstanding AFEs and any additional acreage, seismic and/or drilling cost requirements that might arise from our existing opportunities. We may alter or vary all or part of any planned capital expenditures for reasons including, but not limited to changes in circumstances, unforeseen opportunities, the inability to negotiate favorable acquisition, farmout, joint venture or divestiture terms, commodity prices, lack of cash flow, and lack of additional funding.
Reserves
During the six months ended September 30, 2011, our proved reserves in barrels of oil equivalent (“BOE”) and present value of estimated future cash flows, before income taxes, discounted at 10% (“PV-10”) increased approximately 2% from March 31, 2011 from 1,137,063 and $20,032,664, respectively, to 1,158,418 and $22,159,156, respectively. The increase resulted from newly developed reserves coupled with the increase in first day of the month prices for October 1, 2010 through September 1, 2011, compared to those for April 1, 2010 through March 1, 2011, in accordance with SEC pricing rules.
Contemplated Activities
We are continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. Our policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken. We caution that the absence of news and/or press releases should not be interpreted as a lack of development or activity.
Divestitures/Abandonments
We sold one well during the six months ended September 30, 2011.
Other Commitments
Other than the aforementioned outstanding AFEs, we do not have any other commitments beyond our office lease and software maintenance contracts. See further detail in the notes to the Condensed Consolidated Financial Statements.
Impact of Inflation and Pricing
We deal primarily in U.S. dollars. Inflation has not had a material impact on the Company in recent years because of the relatively low rates of inflation in the United States. However, the oil and natural gas industry can be cyclical and the demand for production places pressure on the economic stability and pricing within the industry. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to lag and may not adjust downward in proportion to declining prices. Changes in prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel. While we do not presently expect business costs to materially rise, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
13
The following provides selected financial information and averages for the three and six months ended September 30, 2011 and 2010.
| Three Months Ended September 30, | Six Months Ended September 30, | |||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
Revenue
|
||||||||||||||||
|
Oil
|
$ | 2,185,000 | $ | 1,642,000 | $ | 4,372,000 | $ | 3,219,000 | ||||||||
|
Gas
|
320,000 | 328,000 | 613,000 | 514,000 | ||||||||||||
|
Total revenue 1
|
2,505,000 | 1,970,000 | 4,985,000 | 3,733,000 | ||||||||||||
|
Total production expense 2
|
1,026,000 | 764,000 | 1,959,000 | 1,391,000 | ||||||||||||
|
Gross profit
|
$ | 1,479,000 | $ | 1,026,000 | $ | 3,026,000 | $ | 2,342,000 | ||||||||
|
Depletion expense
|
$ | 217,000 | $ | 299,000 | $ | 402,000 | $ | 549,000 | ||||||||
|
Sales volume
|
||||||||||||||||
|
Oil (Bbls)
|
25,056 | 25,551 | 47,618 | 48,773 | ||||||||||||
|
Gas (Mcfs) 3
|
46,259 | 44,338 | 77,662 | 68,302 | ||||||||||||
|
Average sales price 4
|
||||||||||||||||
|
Oil (per Bbl)
|
$ | 87.20 | $ | 64.26 | $ | 91.81 | $ | 66.00 | ||||||||
|
Gas (per Mcf)
|
$ | 6.92 | $ | 7.40 | $ | 7.89 | $ | 7.53 | ||||||||
|
Average per BOE 5
|
||||||||||||||||
|
Production expense 3, 4
|
$ | 31.31 | $ | 23.19 | $ | 32.35 | $ | 23.12 | ||||||||
|
Gross profit 4
|
$ | 45.14 | $ | 36.61 | $ | 49.97 | $ | 38.93 | ||||||||
|
Depletion expense 4
|
$ | 6.62 | $ | 9.08 | $ | 6.64 | $ | 9.13 | ||||||||
|
1
|
Amount does not include water service and disposal revenue. For the three and six months ended September 30, 2011, this revenue amount is net of $40,000 and $85,000, respectively, in well service and water disposal revenue, which would otherwise total $2,545,000 and $5,070,000, respectively, in revenue, compared to $27,000 and $28,000 in the respective periods ended September 30, 2010, to total $1,997,000 and $3,761,000 for the comparable three and six month periods ended September 30, 2010.
|
|
|
2
|
Overall lifting cost (oil and gas production costs, including production taxes and the cost of workovers)
|
|
|
3
|
Estimates of volumes are inherent in reported volumes to coincide with revenue accruals as a result of the timing of sales information reporting by third party operators.
|
|
|
4
|
Averages calculated based upon non-rounded figures
|
|
|
5
|
Per equivalent barrel (6 thousand cubic feet, “Mcf”, of gas is equivalent to 1 barrel, “Bbl”, of oil)
|
14
Overview. Net income for the three months ended September 30, 2011, was $728,000 compared to net income of $724,000 for the three months ended September 30, 2010, a 1% increase. Net income for the six months ended September 30, 2011, was $1,393,000 compared to net income of $1,102,000 for the six months ended September 30, 2010, a 26% increase.
The rise in net income resulted from the 27% increase in revenues for the three month period offset by a 25% increase in expenses for the three month periods. Similarly, for the respective six month periods, revenues rose 35% and were offset by a 24% rise in expenses.
Revenues. Oil sales revenue increased $543,000 (33%) and $1,153,000 (36%), respectively, for the three and six months ended September 30, 2011, compared to the three and six months ended September 30, 2010, due to a higher realized price per barrel, despite the decline in production for each period.
Gas sales revenue decreased $8,000 (2%) and increased $99,000 (19%), respectively, for the three and six months ended September 30, 2011, compared to the three and six months ended September 30, 2010, as a result of fluctuations in the price per Mcf for the respective periods, coupled with increases in production.
Volumes and Prices. Oil sales volume declined 2% for each the three and six months ended September 30, 2011, compared to the three and six months ended September 30, 2010. The 36% and 39% increase in average price per barrel for the respective periods positively affected oil revenues.
Gas sales volume rose 4% and 14% for the three and six months ended September 30, 2011, respectively, from the three and six months ended September 30, 2010, primarily due to the recompletion of nine of the existing Codell wells into the J-Sand formation. Gains in revenue from natural gas sales for the three and six month periods were offset by or further benefited from changing prices. A 6% decline in price was realized during the three months ended September 30, 2011, compared to the three months ended September 30, 2010, while a 5% price hike was evident in the six months ended September 30, 2011, due to higher prices in the first quarter of this fiscal year compared to the same quarter the previous fiscal year.
Production Expense. Production expense is comprised of the following items:
|
Three Months Ended
September 30,
|
Six Months Ended
September 30,
|
|||||||||||||||
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|||||||||
|
Lease operating costs
|
$
|
551,000
|
$
|
416,000
|
$
|
1,077,000
|
$
|
819,000
|
||||||||
|
Workover costs
|
|
161,000
|
153,000
|
|
361,000
|
209,000
|
||||||||||
|
Production taxes
|
200,000
|
147,000
|
338,000
|
273,000
|
||||||||||||
|
Transportation and other costs
|
|
114,000
|
48,000
|
|
183,000
|
90,000
|
||||||||||
|
Total production expense
|
$
|
1,026,000
|
$
|
764,000
|
$
|
1,959,000
|
$
|
1,391,000
|
||||||||
Oil and gas production expense increased $209,000 (34%) and $503,000 (45%) for the three and six months ended September 30, 2011, respectively, over the expenses for the three and six months ended September 30, 2010, partially in connection with the increase in wells and partially due to larger workover operations in the current quarter.
Routine lease operating expense (“LOE”), consisting of lease operating costs, transportation and other costs, per BOE was $20.30 for the three months ended September 30, 2011, compared to $14.09 for the three months ended September 30, 2010. As a percent of oil and gas sales revenue, routine LOE was 27% for the three months ended September 30, 2011, compared to 24% for the three months ended September 30, 2010. This increase in proportion to revenue reflects the overall rise in costs; transportation costs in particular spiked. Excess costs associated with flooding in Montana, North Dakota and Wyoming negatively affect this ratio. Additionally, certain costs are fixed regardless of production volume and revenue dollars, which is apparent this quarter as production lags costs on wells that are just coming on-line.
15
LOE for the six months ended September 30, 2010 compared to the six months ended September 30, 2011 shifted similarly to the three month comparables – from $15.11 to $20.81, respectively, per BOE, and 24% to 25%, respectively, as a percent of oil and gas sales revenue for the six months ended September 30, 2010, compared to the six months ended September 30, 2011.
Production taxes, which are generally a percentage of oil and gas sales revenue, increased 36% and 24%, respectively, for the three and six months ended September 30, 2011, compared to the three months ended September 30, 2010. As a percent of oil and gas sales revenue, production taxes were at or about 7% to 8% for both the three and six month periods each year. Production taxes are primarily based on the wellhead values of production, though normal fluctuations occur in the percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, changes in the assessed values of oil and gas properties and equipment for purposes of ad valorem taxes, and changes in the proportion of our production between states and counties. Because production tax rates vary from one state to the next as well as across the various counties within a given state, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those jurisdictions.
The overall lifting cost (oil and gas production costs, including production taxes as well as workovers) per BOE increased from $23.19 for the three months ended September 30, 2010, to $31.31 for the three months ended September 30, 2011, primarily as a result of rising industry costs coupled with workover costs to improve results on 19 wells. A similar impact is evident in the respective six month periods, with the overall lifting cost at $32.25 for the six months ended September 30, 2011, compared to $23.12 for the six months ended September 30, 2010.
Other Expenses.
Depletion and depreciation decreased $80,000 (26%) and $143,000 (25%), respectively, for the three and six months ended September 30, 2011, compared to the three and six months ended September 30, 2010, as a result of the near 20% increase in reserves, offset by the increase in depletable property during the past twelve months.
G&A expense increased $177,000 (54%) and $228,000 (32%), respectively, for the three and six months ended September 30, 2011, over the expense for the three and six months ended September 30, 2010. This rise in costs is comprised primarily of compensation-related expenses, which account for fluctuations of $135,000 and $195,000 for the three and six month periods, respectively, with respect to the increase in number of employees, additional Board member, and consultants. Public company expenses rose $26,000 for each of the three and six month periods.
As total G&A dollars rose, the expense per BOE increased from $10.02 for the three months ended September 30, 2010, to $15.47 for the three months ended September 30, 2011, and from $11.99 for the six months ended September 30, 2010, to $15.67 for the six months ended September 30, 2011. In proportion to total revenue, G&A expense was consistent at 19% for both the six months ended September 30, 2011 and 2010, while increasing from 17% for the three months ended September 30, 2010, to 20% for the three months ended September 30, 2011.
Income Tax. For the three and six months ended September 30, 2011, we recorded income tax expense of $74,000 and $320,000, respectively, as compared to benefits of $166,000 and $97,000 for the three and six months ended September 30, 2010. Our effective income tax rate was 9.2% and 18.7%, respectively, for the three and six months ended September 30, 2011. We recognized expenses for the three and six months ended September 30, 2011, compared to benefits for the three and six months ended September 30, 2010, as a result of having lower deductions for statutory depletion available in the current period in addition to the prior year periods reflecting true-up adjustments of deferred tax benefits from amounts originally estimated on the tax provision for the year ended March 31, 2010.
Off Balance Sheet Arrangements
We have no significant off balance sheet transactions, arrangements or obligations.
As a “smaller reporting company,” we are not required to provide this information.
16
ITEM 4. CONTROLS AND PROCEDURES
As defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, the phrase “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2011. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Interim Chief Financial Officer concluded that, as of September 30, 2011, our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
17
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
As a “smaller reporting company,” we are not required to provide this information.
Unregistered Sales of Equity Securities
Not applicable.
Purchases of Equity Securities
The following summarizes monthly share repurchase activity for the three months ended September 30, 2011:
|
Total Number of Shares Purchased
|
Average Price Paid Per Share
|
Number of Shares Purchased as Part of a Publicly Announced Plan¹
|
Maximum Shares that May Yet be Purchased under the Plan¹
|
|||||||||||||
|
July 1, 2011 – July 31, 2011
|
—
|
$
|
—
|
—
|
109,440
|
|||||||||||
|
August 1, 2011 – August 31, 2011
|
—
|
$
|
—
|
—
|
109,440
|
|||||||||||
|
September 1, 2011 – September 30, 2011
|
6,156
|
$
|
13.65
|
6,156
|
103,284
|
|||||||||||
|
Total
|
6,156
|
6,156
|
||||||||||||||
|
¹
|
The share buyback program was authorized by the Company’s Board of Directors in 2008.
|
Effective December 31, 2010, the Board of Directors authorized and effected a 1-for-10 reverse stock split which converted ten (10) shares of the Company’s common stock into one (1) share of common stock. References to the number of treasury shares and per share amounts reflect the reverse stock split.
None.
None.
None.
18
ITEM 6. EXHIBITS
|
Exhibit No.
|
Document
|
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).
|
||
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer).
|
||
|
Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, President and Chief Executive Officer).
|
||
|
Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Jim Poage, Interim Chief Financial Officer).
|
||
|
101
|
The following materials from the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Operations, (iii) the Unaudited Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Unaudited Condensed Consolidated Financial Statements, tagged as blocks of text.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed by the following authorized persons on behalf of Earthstone Energy, Inc.
| EARTHSTONE ENERGY, INC. | |||
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By:
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/s/ /s/ Ray Singleton | |
| Ray Singleton | |||
| President and Chief Executive Officer | |||
| By: | /s/ Jim Poage | ||
| Jim Poage | |||
| Interim Chief Financial Officer | |||
| Date: November 7, 2011 | |||
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