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ESTE > SEC Filings for ESTE > Form 10-Q on 12-Nov-2013All Recent SEC Filings

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Form 10-Q for EARTHSTONE ENERGY INC


12-Nov-2013

Quarterly Report


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, 2013, 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 the 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," 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 influenced by the prevailing prices of crude oil and natural gas. Changes in commodity prices affect, both positively and negatively, our financial condition, liquidity, ability to obtain financing and operating results. Changes in commodity prices may influence, both positively and negatively, the amount of crude oil and natural gas that we choose to produce. Prevailing prices for such commodities fluctuate in response to changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Inherently, the prices received for crude oil and natural gas sales are unpredictable, and such volatility is expected. All of our production is sold at market prices. Obviously, if the commodity indexes fluctuate, the price that we receive for our oil and natural gas sales will fluctuate. Therefore, the amount of revenue that we realize, as well as our estimates of future revenues, 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 and available line of credit, should enable us to meet our existing and normal recurring obligations during the next year and beyond.

On December 21, 2012, we entered into a $25 million senior secured revolving bank Credit Facility with the Bank of Oklahoma ("Bank") which provides an additional source of funds to pay our share of drilling and completion costs incurred on wells drilled and completed in the Williston Basin. The initial borrowing base on the Credit Facility was $6 million. Among other provisions, the Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. At the end of the quarter ending June 30, 2013, we were not in compliance with the current ratio covenant as defined by the Credit Facility. For further information concerning the Credit Facility and its terms, see our Form 8-K filed with the SEC on January 3, 2013.

Effective September 10, 2013, we entered into a Waiver and First Amendment to Credit Agreement (the "Amended Credit Facility") with the Bank of Oklahoma in connection with a semiannual redetermination of the borrowing base. The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination. The covenant violation was waived under terms of the Amended Credit Facility. As of September 30, 2013, we had an outstanding balance due of $8 million under the Amended Credit Facility and were in compliance with all covenants contained in the Amended Credit Facility. Our ability to remain in compliance with the financial covenants may be affected by events and other factors beyond our control, including market prices for our oil and gas and the rate at which the operators of projects in which we participate drill. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect our liquidity by rendering us unable to borrow further under the Amended Credit Facility. For further information concerning the Amended Credit Facility and its terms, see the Exhibits below in Part II - Item 6 of this Form 10-Q.

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 existing and newly acquired properties.

We have received numerous inquiries regarding the possibility of funding our efforts through equity contributions. Given strong cash flows, 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 and available cash and bank debt financing were insufficient, it is possible we would consider alternative means of obtaining additional financing.


Hedging. During the six months ended September 30, 2013 and 2012, we did not participate in any hedging activities, nor did we have any open futures or option contracts.

Working Capital. At September 30, 2013, we had a working capital deficit of $694,000 (a current ratio of 0.91:1) compared to a working capital surplus at March 31, 2013 of $775,000 (a current ratio of 1.14:1). The decrease in current ratio is primarily a result of the use of accrued payables for the development and exploration of oil and gas properties and ongoing oil and gas operations.

Cash Flow. Cash provided by operating activities was $4,217,000 for the six months ended September 30, 2013, compared to $518,000 for the six months ended September 30, 2012. Changes in operating cash relate primarily to the increase in net income adjusted for non-cash expenses for the six months ended September 30, 2013 compared to the comparable prior period ended September 30, 2012. Increases in deferred income tax expense and depletion primarily relate to the increase in the oil and gas property balances. The timing and payment of accounts payable, accrued and other liabilities, especially pertaining to capital expenditure outlays, were also factors in deriving net cash flows from operations.

Overall, net cash used in investing activities increased for the six months ended September 30, 2013, to $7,648,000 from $4,720,000 for the six months ended September 30, 2012. This was the result of an increase in the number of wells drilled and completed during the current period compared to the comparable prior period, as explained in "Capital Expenditures" below.

Net cash provided by financing activities was $3,995,000 for the six months ended September 30, 2013 related to borrowing on our Credit Facility. No cash was provided by or used in financing activities for the six months ended September 30, 2012.

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 statements 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, 2013, we spent $9,713,000 on various projects. This compares to $6,396,000 for the six months ended September 30, 2012. During the six months ended September 30, 2013, capital expenditures were comprised of drilling and completions of our wells producing as of period end (65%), drilling of six wells to be completed as of calendar year end (29%), and acquiring leasehold acreage (6%). The majority (92%) of capital expenditures were spent in the Williston basin. The remainder was spent in other areas on property improvements and leasehold acreage.

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 neither sold nor plugged any wells during the six months ended September 30, 2013.

Impact of Inflation and Pricing

Inflation has not had a material impact on us 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.

Other Commitments

We do not have any other commitments beyond our office lease and software maintenance contracts.


Results of Operations

The following provides selected financial information and averages for the three
and six months ended September 30, 2013 and 2012.

                                 Three Months Ended               Six Months Ended
                                    September 30,                   September 30,

                                2013            2012            2013            2012
Revenue
   Oil                       $ 4,230,000     $ 2,546,000     $ 7,610,000     $ 4,674,000
   Gas 1                         397,000         154,000         599,000         246,000
Total revenue 2                4,627,000       2,700,000       8,209,000       4,920,000

Total production expense 3     1,299,000       1,085,000       2,443,000       2,115,000

Gross profit                 $ 3,328,000     $ 1,615,000     $ 5,766,000     $ 2,805,000

Depletion expense            $   951,000     $   446,000     $ 1,710,000     $   725,000

Sales volume
   Oil (Bbls)                     42,706          31,169          79,673          58,168
   Gas (Mcfs) 4                   55,900          30,818          84,123          45,384

Average sales price 5
   Oil (per Bbl)             $     99.05     $     81.68     $     95.52     $     80.35
   Gas (per Mcf) 6           $      7.10     $      5.00     $      7.12     $      5.42

Average per BOE 7
   Production expense 4, 5   $     24.97     $     29.89     $     26.07     $     32.18
   Gross profit 5            $     63.97     $     44.48     $     61.54     $     42.67
   Depletion expense 5       $     18.28     $     12.28     $     18.25     $     11.03

1 Amount includes natural gas liquid (NGL) revenue. For the three months ended September 30, 2013 and 2012, the NGL revenue included in the gas revenue amount was $145,000 and $43,000, respectively. For the six months ended September 30, 2013 and 2012, the NGL revenue included in the gas revenue amount was $217,000 and $78,000, respectively.

2 Amount does not include water service and disposal revenue. For the three and six months ended September 30, 2013, this revenue amount is net of $45,000 and $58,000, respectively, in well service and water disposal revenue, which would otherwise total $4,672,000 and $8,267,000, respectively, in revenue, compared to $109,000 and $236,000 in the respective periods ended September 30, 2012 to total $2,809,000 and $5,156,000 for the comparable three and six month periods ended September 30, 2012.

3 Overall lifting cost (oil and gas production costs, including production taxes and the cost of workovers)

4 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.

5 Averages calculated based upon non-rounded figures.

6 Average gas sales price per Mcf is calculated by dividing total gas and NGL revenue by the gas sales volume per Mcf. For the three months ended September 30, 2013 and 2012, gas sales price per Mcf, exclusive of NGL revenues, was $4.51 per Mcf and $3.60 per Mcf, respectively. For the six months ended September 30, 2013 and 2012, gas sales price per Mcf, exclusive of NGL revenues, was $4.54 per Mcf and $3.70 per Mcf, respectively.

7 Per equivalent barrel (6 thousand cubic feet, "Mcf", of gas is equivalent to 1 barrel, "Bbl", of oil)

Three months ended September 30, 2013 compared to three months ended September 30, 2012

Overview. Net income for the three months ended September 30, 2013, was $1,224,000 compared to net income of $486,000 for the three months ended September 30, 2012. The increase in net income resulted from the increase in oil and gas sales volumes and prices as described in "Revenues" and "Volumes and Prices" below.

Revenues. Oil sales revenue increased $1,684,000 (66%) for the three months ended September 30, 2013 to $4,230,000 from $2,546,000 for the three months ended September 30, 2012, due to the increase in reported sales volumes and a higher realized price per barrel as described in "Volumes and Prices" below.

Gas sales revenue increased $243,000 (158%) for the three months ended September 30, 2013, compared to the three months ended September 30, 2012, as a result of the increase in reported sales and a higher realized price per Mcf as described in "Volumes and Prices" below.


Volumes and Prices. Oil sales volumes increased by 37% for the three months ended September 30, 2013, compared to the three months ended September 30, 2012. In addition, the average price per barrel increased by 21% for the three months ended September 30, 2013 over the three months ended September 30, 2012. The increase in oil sales volumes for the three months ended September 30, 2013 when compared to the three months ended September 30, 2012 was the result of an increase in sales from newly producing wells, offset partially by declines in existing wells.

Gas sales volumes increased by 81% for the three months ended September 30, 2013, compared to the three months ended September 30, 2012. In addition, the average price per Mcf increased by 42% for the three months ended September 30, 2013, compared to the three months ended September 30, 2012. The increase in gas sales volumes for the three months ended September 30, 2013 when compared to the three months ended September 30, 2012 was the result of increased sales volumes from newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells.

Production Expense. Production expense is comprised of the following items:

                                     Three Months Ended
                                        September 30,
                                     2013            2012

Lease operating costs            $   678,000     $   591,000
Workover costs                       145,000         216,000
Production taxes                     431,000         262,000
Transportation and other costs       45,000           16,000
Total production expense         $ 1,299,000     $ 1,085,000

Oil and gas production expense increased $214,000 (20%) for the three months ended September 30, 2013, as compared to the expenses for the three months ended September 30, 2012, largely due to the increase in number of producing wells.

Routine lease operating expense ("LOE"), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $13.90 for the three months ended September 30, 2013, compared to $16.72 for the three months ended September 30, 2012. While the total dollars spent on routine lease operating expense was 19% higher between the comparable periods, the costs are being divided over more BOE in the three months ended September 30, 2013 resulting in a lower cost per BOE.

As a percent of oil and gas sales revenue, routine LOE was 16% for the three months ended September 30, 2013, compared to 22% for the three months ended September 30, 2012. This decrease in cost in proportion to revenue was due to a combination of the increase in oil and gas prices, sales volume, and the number of producing wells between the comparable periods.

Workover operations, which generally consist of downhole repairs on a producing well, are conducted to restore or increase production and are generally random in nature. Therefore, workovers account for unpredictable fluctuations in oil and gas expense from period to period. The number of wells on which workover costs are expended varies as does the extent of workover operations. Workover expenses decreased $71,000 (33%) for the three months ended September 30, 2013, compared to the respective period ended September 30, 2012. Consequently, workover costs in the second quarter of fiscal year 2014 decreased to $2.79 per BOE from $5.95 per BOE in the second quarter of fiscal 2013.

Production taxes for the three months ended September 30, 2013 increased 65% over the three months ended September 30, 2012. As a percent of oil and gas sales revenue, production taxes decreased to 9% for the three months ended September 30, 2013, compared to 10% for the three months ended September 30, 2012. Because production tax rates vary from state to state, our average production tax rate will vary depending on the quantities sold from each state and the production tax rates, and incentives, in effect for those jurisdictions.


While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased during the current quarter in relation to the comparable period in the prior year, those costs are spread over larger reported volumes, per BOE, for the three months ended September 30, 2013, compared to the three months ended September 30, 2012, causing the costs per BOE to decrease from $29.89 to $24.97.

Other Expenses. Depletion and depreciation increased $519,000 (113%) for the three months ended September 30, 2013, compared to the three months ended September 30, 2012. The increase in expense was a result of the addition of capital costs for newly drilled wells transferred into the pool of depletable property costs, as well as an increase in the costs related to future development of proved undeveloped wells between the comparable periods.

General and Administrative ("G&A") expense increased $32,000 (5%) for the three months ended September 30, 2013, over the expense for the three months ended September 30, 2012. While G&A expense increased slightly during the current quarter in relation to the comparable period in the prior year, those costs are spread over larger reported volumes, per BOE, for the three months ended September 30, 2013, compared to the three months ended September 30, 2012, causing the costs per BOE to decrease from $17.27 to $12.67.

Income Tax. For the three months ended September 30, 2013, we recorded income tax expense of $405,000, as compared to $92,000 for the three months ended September 30, 2012. Our effective income tax rate was 24.9% for the three months ended September 30, 2013. The overall effective tax rate expressed as a percentage of book income before income tax for the three months ended September 30, 2013, as compared to the same period in 2012, was higher due primarily to a higher pre-tax income compared to the comparable period. For the three months ended September 30, 2013, pre-tax income was $1,629,000 compared to $578,000 for the prior period.

Six months ended September 30, 2013 compared to six months ended September 30, 2012

Overview. Net income for the six months ended September 30, 2013, was $1,917,000 compared to net income of $756,000 for the six months ended September 30, 2012. The increase in net income resulted from the increase in oil and gas sales volumes and prices as described in "Revenues" and "Volumes and Prices" below and an increase in expenses for the six month period.

Revenues. Oil sales revenue increased 63% for the six months ended September 30, 2013, from $4,674,000 for the six months ended September 30, 2012 to $7,610,000 for the current period, due to the increase in reported sales volumes and a higher realized price per barrel as described in "Volumes and Prices" below.

Gas sales revenue increased $353,000 (143%) for the six months ended September 30, 2013, compared to the six months ended September 30, 2012, as a result of the increase in reported sales volumes and a higher realized price per Mcf as described in "Volumes and Prices" below.

Volumes and Prices. Oil sales volumes rose by 37% for the six months ended September 30, 2013, compared to the six months ended September 30, 2012. The average price per barrel increased by 19% for the six months ended September 30, 2013, compared to the six months ended September 30, 2012. The rise in oil sales volumes for the six months ended September 30, 2013 was the result of a significant contribution from 22 new gross producing oil wells in North Dakota since the comparable period in the prior year.

Gas sales volumes increased by 85% for the six months ended September 30, 2013, compared to the six months ended September 30, 2012. In addition, the average price per Mcf increased by 31% for the six months ended September 30, 2013, compared to the six months ended September 30, 2012. The increase in gas sales volumes for the six months ended September 30, 2013 when compared to the six months ended September 30, 2012 was the result of increased sales volumes from newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells.

Production Expense. Production expense is comprised of the following items:

                                      Six Months Ended
                                        September 30,
                                     2013            2012

Lease operating costs            $ 1,375,000     $ 1,249,000
Workover costs                       261,000         387,000
Production taxes                     740,000         458,000
Transportation and other costs        67,000          21,000

Total production expense         $ 2,443,000     $ 2,115,000


Oil and gas production expense increased $328,000 (16%) for the six months ended September 30, 2013, over the expenses for the six months ended September 30, 2012, largely due to the increase in number of producing wells.

Routine lease operating expense ("LOE"), consisting of field personnel, fuel/power, chemicals, disposal and other costs, per BOE was $15.39 for the six months ended September 30, 2013, compared to $19.32 for the six months ended September 30, 2012. While the total dollars spent on routine lease operating expense was 14% higher between the comparable periods, the costs are being divided over more BOE in the six months ended September 30, 2013 resulting in a lower cost per BOE.

As a percent of oil and gas sales revenue, routine LOE was 18% for the six months ended September 30, 2013 and 26% for the six months ended September 30, 2012. This decrease of routine LOE in proportion to revenue was due to a combination of the increase in oil and gas prices, sales volume, and the number of producing wells between the comparable periods.

Workover operations, which generally consist of downhole repairs on a producing well, are conducted to restore or increase production and are generally random in nature. Therefore, workovers account for unpredictable fluctuations in oil and gas expense from period to period. The number of wells on which workover costs are expended varies as does the extent of workover operations. Workover expenses decreased $126,000 (33%) for the six months ended September 30, 2013, compared to the respective period ended September 30, 2012. The workover costs were spread over increased sales volumes, resulting in a decrease in workover costs per BOE in the six months ended September 30, 2013 to $2.79 from $5.89 per BOE in the six months ended September 30, 2012.

Production taxes for the six months ended September 30, 2013, increased 62% over the six months ended September 30, 2012, primarily due to the increase in sales volumes. As a percent of oil and gas sales revenue, production taxes remained constant at 9% with the respective prior year six month period. Because production tax rates vary from state to state, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates, and incentives, in effect for those jurisdictions.

While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased during the current period, those costs are spread over greater reported volumes per BOE, for the six months ended September 30, 2013, compared to the six months ended September 30, 2012, causing the cost per BOE to decline from $32.18 to $26.07.

Other Expenses. Depletion and depreciation increased $1,011,000 (134%) for the six months ended September 30, 2013, compared to the six months ended September 30, 2012. The increase in expense was a result of an increase in the addition of capital costs for newly drilled wells into the pool of depletable property costs, as well as an increase in the costs related to future development of proved undeveloped wells between the comparable periods.

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