EARTHSTONE ENERGY INC - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the Quarterly Period Ended March 31, 2017

Or

Commission File No. 001-35049  

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

1400 Woodloch Forest Drive, Suite 300

The Woodlands, Texas 77380

(Address of principal executive offices)

Registrant’s telephone number, including area code:  (281) 298-4246

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to post such filed).    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 definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

                             Large accelerated filer            ☐   Accelerated filer☒  

                             Non-accelerated filer              ☐  (Do not check if a smaller reporting company)Smaller reporting company☐

                             Emerging growth company    ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.        ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

As of April 28, 2017, 22,559,695 shares of common stock, $0.001 par value per share, were outstanding.

TABLE OF CONTENTS

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PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

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EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share amounts)

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

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EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands) 

The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. – Basis of Presentation and Summary of Significant Accounting Policies

Earthstone Energy, Inc. (together with its wholly-owned consolidated subsidiaries, the “Company,” “our,” “we,” “us,” “Earthstone” or similar terms), a Delaware corporation, is a growth-oriented independent oil and natural gas development and production company.  In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities.  Our operations are all in the up-stream segment of the oil and natural gas industry and all our properties are onshore in the United States.  

The accompanying unaudited Condensed Consolidated Financial Statements and notes of Earthstone, have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial statements. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted. The accompanying unaudited Condensed Consolidated Financial Statements and notes should be read in conjunction with the financial statements and notes included in Earthstone’s 2016 Annual Report on Form 10-K.

The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company's financial position, results of operations and cash flows for the periods presented.  The Company’s Condensed Consolidated Balance Sheet at December 31, 2016 is derived from the audited Consolidated Financial Statements at that date.

Prior-period Re-engineering and workovers in the Condensed Consolidated Statements of Operations have been reclassified from its own line item and included in Lease operating expenses, within Operating Costs and Expenses, to conform to current-period presentation.  This reclassification had no effect on Loss from operations, Income (loss) before income taxes, or Net income (loss) for the three months ended March 31, 2017 and 2016.

Recently Issued Accounting Standards

Standards not yet adopted

Revenue Recognition - In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued guidance deferring the effective date of this standards update for one year, to be effective for interim and annual periods beginning after December 15, 2017.  In March 2016, the FASB issued guidance which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued further guidance on identifying performance obligations and clarification of the licensing implementation guidance.  Early adoption of this updated guidance is permitted as of the original effective date of December 31, 2016.  The Company expects to adopt this standards update, as required, beginning with the first quarter of 2018. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Condensed Consolidated Financial Statements.

Leases – In February 2016, the FASB issued updated guidance on accounting for leases.  The update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2019.  The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Condensed Consolidated Financial Statements.

Statement of Cash Flows – In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows.  This update provides guidance on eight specific cash flow issues.  The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented.  Early adoption is permitted.  The Company expects to adopt this standards update, as required, beginning with the first quarter of 2018.  The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Condensed Consolidated Financial Statements.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Business Combinations – In January 2017, the FASB issued updated guidance that clarifies the definition of a business, which amends the guidance used in evaluating whether a set of acquired assets and activities represents a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not considered a business. As a result, acquisition fees and expenses will be capitalized to the cost basis of the property acquired, and the tangible and intangible components acquired will be recorded based on their relative fair values as of the acquisition date. The standard is effective for all public business entities for annual periods beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted for periods for which financial statements have not yet been issued. The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Condensed Consolidated Financial Statements.

Intangibles - Goodwill and Other – In January 2017, the FASB issued updated guidance simplifying the test for goodwill impairment. The update eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The update is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company is in the process of evaluating the impact, if any, on its Condensed Consolidated Financial Statements.

Note 2. Acquisitions

Lynden Arrangement

On May 18, 2016, the Company acquired Lynden Energy Corp. (“Lynden”) in an all-stock transaction (the “Lynden Arrangement”).  The Company acquired all outstanding shares of Lynden’s common stock, through a newly formed subsidiary, with Lynden surviving as a wholly-owned subsidiary of the Company, issuing 3,700,279 shares of its common stock, $0.001 par value per share (the “Common Stock”), to the holders of the common stock of Lynden. The Lynden Arrangement was accounted for as a business combination in accordance with FASB ASC Topic 805, Business Combinations, which, among other things, requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date.    

The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed and resulting goodwill (in thousands, except share and share price amount):

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 3. Fair Value Measurements

FASB ASC Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC 820 is as follows:

Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the three months ended March 31, 2017.

Fair Value on a Recurring Basis

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The swaps are also designated as Level 2 within the valuation hierarchy.

The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the consolidated financial statements.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and goodwill.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. 

Proved Oil and Natural Gas Properties

Proved oil and natural gas properties are measured at fair value on a nonrecurring basis in order to review for impairment. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.

Goodwill

Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors.

Business Combinations

The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on NYMEX commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The future oil and natural gas pricing used in the valuation is a Level 2 assumption. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are described in Note 2. Acquisitions.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Asset Retirement Obligations

The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 10. Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

Note 4. Derivative Financial Instruments

Our hedging activities consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swap agreements. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Consistent with our hedging policy, we have entered into a series of derivative instruments to hedge a significant portion of our expected oil and natural gas production through 2018. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, we believe these instruments reduce our exposure to oil and natural gas price fluctuations and, thereby, allow us to achieve a more predictable cash flow.

Our derivative instruments are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. We do not enter into derivative instruments for trading or other speculative purposes. These transactions are recorded in our Condensed Consolidated Financial Statements in accordance with FASB ASC Topic 815. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Operations.

The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency

The Company had the following open crude oil and natural gas derivative contracts as of March 31, 2017:           

The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands): 

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Condensed Consolidated Statements of Operations (in thousands):

Note 5. Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties.  Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized.  Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in operating income (loss) in the Consolidated Statements of Operations.

The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. Depletion expense for oil and gas producing property and related equipment was $7.8 million and $5.4 million, for the three months ended March 31, 2017 and 2016, respectively.

Proved Properties

The Company reviews its proved oil and natural gas properties for impairment on a field basis when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or a significant decrease in future commodity prices. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value.

Unproved Properties

Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.

The Company reviews its unproved properties periodically for impairment.  In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.

Impairments to Oil and Natural Gas Properties

The Company did not record any impairments to its oil and natural gas properties for the three months ended March 31, 2017 and 2016.

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 6. Net Income (Loss) Per Common Share

Net income (loss) per common share—basic is calculated by dividing Net income (loss) by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income (loss) by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net income (loss) per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares would have an anti-dilutive effect. A reconciliation of Net income (loss) per common share is as follows:

For the three months ended March 31, 2016, there were no restricted stock units issued or outstanding under the Company’s 2014 Long-Term Incentive Plan.

Note 7. Common Stock

At March 31, 2017 and December 31, 2016, there were 22,575,052 and 22,289,177 shares of Common Stock issued, respectively, both including 15,357 shares of treasury stock held by the Company.

During the three months ended March 31, 2017, 285,875 shares of Common Stock were issued as a result of the vesting of restricted stock units under the Company’s 2014 Long-Term Incentive Plan.

During the three months ended March 31, 2016, there were no changes in Common Stock.

Note 8. Stock-Based Compensation

The Company’s amended 2014 Long-term Incentive Plan (the “2014 Plan”) allows, among other things, for the grant of restricted stock units (“RSUs”).  The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting.  The Company determines the fair value of granted RSUs based on the market price of the Common Stock of the Company on the date of the grant.  Compensation expense is for granted RSUs is recognized on a straight-line basis over the vesting and is net of forfeitures, as incurred.

The table below summarizes nonvested RSU awards activity for the three months ended March 31, 2017:

The future compensation cost of the RSU awards at March 31, 2017 is $5.5 million which will be amortized over the remaining vesting period. The weighted average remaining vesting period of the future compensation cost is 0.65 years. Stock-based

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

compensation for the three months ended March 31, 2017 recorded in the Condensed Consolidated Statements of Operations was $1.3 million, with a corresponding increase in Additional paid-in capital in the Condensed Consolidated Balance Sheet.

No RSUs were issued prior to May 20, 2016. Therefore, there was no nonvested RSU awards activity, nor any stock-based compensation recognized in the Condensed Consolidated Statements of Operations, for the three months ended March 31, 2016.

Note 9. Long-Term Debt

Credit Agreement

In December, 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility (the “Credit Agreement”).  The borrowing base under the Credit Agreement is subject to redetermination on May 1 and November 1 each year, as well as other elective borrowing base redeterminations.  As of March 31, 2017, outstanding borrowings under the Credit Agreement bear interest at a rate elected by the Company that is equal to a base rate (which is equal to the greater of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month LIBOR plus 1.00%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.25% to 2.25% for base rate loans and from 2.25% to 3.25% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee of 0.50% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. The Company is also required to pay customary letter of credit fees. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on December 19, 2018. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets.

As of March 31, 2017, the Company had an $80.0 million borrowing base, of which $10.0 million of debt was outstanding, bearing an interest rate of 3.084%, as well as a $0.1 million letter of credit outstanding related to our office lease, resulting in $69.9 million of borrowing base availability under the Credit Agreement.

The Credit Agreement contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum modified current ratio which includes the available borrowing base of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. The Company is also required to submit an audited annual report 120 days after the end of each fiscal year. As of March 31, 2017, the Company was in compliance with these covenants under the Credit Agreement.

Promissory Note

In July 2016, the Company issued a $5.1 million unsecured promissory note (the “Note”) to a drilling rig contractor in settlement of rig idle charges and a contract termination fee. These expenses were recorded in the Company’s Condensed Consolidated Statement of Operations during 2016. The Note is payable in monthly installments over a three-year period maturing in July 2019, bearing an annualized interest rate of 8.0% for the first 12 months, 10.0% for the subsequent 12 months, and 12.0% for the last 12 months, with no prepayment penalty.  Interest expense is recognized using the effective interest method of approximately 9.1% over the life of the note. As of March 31, 2017, the Company had $3.9 million outstanding under the note with $1.6 million included in the current portion of long-term debt.  

Total Long-Term Debt

The following table below summarizes long term debt (in thousands):

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the three months ended March 31, 2017, the Company had no borrowings and $0.4 million in repayments of borrowings.

For the three months ended March 31, 2017 and 2016, interest on borrowings averaged 4.92% and 2.79% per annum, respectively.  Average interest on borrowings for the three months ended March 31, 2017 and 2016, excludes commitment fees of $0.1 million and $0.1 million, respectively.  The Company did not capitalized any costs associated with its borrowings for the three months ended March 31, 2017.  The Company capitalized $0.003 million of costs associated with its borrowings for the three months ended March 31, 2016. These costs are included in Other noncurrent assets on the Company’s Condensed Consolidated Balance Sheets. The Company’s policy is to capitalize the financing costs associated with the Credit Agreement and amortize those costs on a straight-line basis over the term of the Credit Agreement.  

Note 10. Asset Retirement Obligations

The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

The following table summarizes the Company’s asset retirement obligation transactions recorded during the three months ended March 31, (in thousands):   

Note 11. Related Party Transactions

FASB ASC Topic 850, Related Party Disclosures, requires that information about transactions with related parties that would make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance.

Flatonia Energy, LLC (“Flatonia”), which owns approximately 13.3% of our Common Stock, is a party to a joint operating agreement (the “Operating Agreement”) with the Company. The Operating Agreement covers certain jointly owned oil and natural gas properties located in the Eagle Ford trend in Texas. In connection with the Operating Agreement, we made payments to Flatonia of $7.2 million and $12.2 million and received $1.5 million and $2.8 million in the three months ended March 31, 2017 and 2016, respectively. Amounts receivable from Flatonia in connection with the Operating Agreement were $1.2 million and $1.6 million at March 31, 2017 and 2016, respectively. Amounts payable to Flatonia in connection with the Operating Agreement were $2.3 million and $4.0 million at March 31, 2017 and 2016, respectively.          

Note 12. Commitments and Contingencies  

Legal

From time to time, the Company and its subsidiaries may be involved in various legal proceedings and claims in the ordinary course of business.  In July 2015, EF Non-Op, LLC, a subsidiary of the Company, filed suit in the 125^th Judicial District Court of Harris County, Texas against the operator of its properties in LaSalle County, Texas. In the case EF Non-Op, LLC vs. BHP Billiton Petroleum Properties (N.A.), LP (F/K/A Petrohawk Properties, LP), the Company claims the operator has breached the applicable joint operating agreements in numerous ways, including, but not limited to, improper authorization for expenditure requests, improper and imprudent operations, misrepresentation of charges and excessive billings, as well as refusal to provide requested information. The Company also claims damages from negligent representation and fraud.  The Company is seeking all relief to which it is entitled, including consequential damages and attorneys’ fees. BHP Billiton has claimed they are owed unpaid lease operating expenses and attorneys’ fees. With respect to a portion of the litigation associated with nine non-operated gas wells that were drilled in 2014 and placed on production in the first half of 2015, BHP Billiton in early 2016 elected to deem the Company as a non-consenting working interest owner regarding costs associated with the drilling, completing and operating of these nine wells, as BHP’s sole and exclusive remedy.  The Company has accepted this “non-consent” status. The litigation is continuing with respect to the other disputes. The

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EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

outcome of remaining disputes in this proceeding is uncertain, and while the Company is confident in its position, any potential monetary recovery or loss to the Company cannot be estimated at this time.

Environmental and Regulatory

As of March 31, 2017, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

Note 13. Income Taxes

Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from the Lynden Arrangement that includes Lynden USA, Inc. (“Lynden US”), Earthstone Energy, Inc. (“Earthstone US”), and Lynden Energy Corp. (“Lynden Canada”), As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone.

During the three months ended March 31, 2017, we recorded an income tax benefit for Lynden US of $0.04 million as a result of a pre-tax net loss of $0.13 million. Earthstone US had pre-tax net income of $0.83 million and recorded no income tax expense as a result of a full valuation allowance recorded against the net deferred tax asset, as future realization of the net deferred tax asset cannot be assured. Additionally, Earthstone US incurred non-deductible shortfalls on stock compensation on the RSUs that vested during the period, for which no income tax expense was recorded as a result of the full valuation allowance recorded against the net deferred tax asset. For Lynden Canada, there was no material net income (loss), or related income tax expense (benefit), for the three months ended March 31, 2017.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statement Regarding Forward-Looking Information

This discussion and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to numerous risks, uncertainties and assumptions. Certain of these risks are summarized in this report and under “Item 1A. Risk Factors” in our 2016 Annual Report on Form 10-K that we filed with the Securities and Exchange Commission (“SEC”) on March 15, 2017, which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

You should read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2016, which are included in our 2016 Annual Report on Form 10-K.

Overview

Earthstone Energy, Inc. (together with our wholly-owned consolidated subsidiaries, the “Company,” “our,” “we,” “us,” “Earthstone” or similar terms), a Delaware corporation, is a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions and mergers and, to a lesser extent, exploration activities.  Our operations are all in the up-stream segment of the oil and natural gas industry and all our properties are onshore in the United States. At present, our primary assets are located in the Midland Basin of west Texas, the Eagle Ford trend of south Texas and the Bakken/Three Forks formations of North Dakota.

Recent Developments

Bold Contribution Agreement

On November 7, 2016, we entered into a contribution agreement (the “Bold Contribution Agreement”), by and among the Company, Earthstone Energy Holdings, LLC, a newly formed Delaware limited liability company (“EEH”), Lynden USA, Inc., a Utah corporation (“Lynden USA”), Lynden USA Operating, LLC, a newly formed Texas limited liability company (all wholly-owned subsidiaries of the Company), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”).

Under the Bold Contribution Agreement, the terms of which were unanimously approved by a special committee of disinterested members of the Company’s Board of Directors and the full Board (i) the Company will recapitalize the Common Stock into two classes, consisting of Class A and Class B, and all of its existing Common Stock will be converted into Class A common stock. Bold Holdings will purchase approximately 36.1 million shares of the Company’s Class B common stock for nominal consideration, with the Class B common stock having no economic rights in the Company other than voting rights on a pari passu basis with the Class A common stock. In addition, EEH will issue approximately 22.3 million of its membership units to the Company and Lynden USA, in the aggregate, and approximately 36.1 million membership units to Bold Holdings in exchange for each of the Company, Lynden USA and Bold Holdings transferring all of their assets to EEH; and (iii) each Bold membership unit in EEH, together with one share of Bold Holdings Class B common stock, will be convertible into Class A common stock on a one-for-one basis. Therefore, upon the closing of the transaction, stockholders of the Company and unitholders of Bold Holdings are expected to own approximately 39% and 61%, respectively of the combined company’s then outstanding Class A and Class B common stock on a fully diluted basis. After closing, the Company expects to conduct its activities through EEH and will be its sole managing member. The transaction is expected to close in the second quarter of 2017 and is subject to approval of the Company’s stockholders and other customary closing conditions.

The Company gave notice of a special meeting of stockholders to be held in its corporate offices on May 9, 2017, in a definitive proxy statement filed with the SEC on Schedule 14A on April 7, 2017 to consider and vote upon, among other things, a proposal to approve and adopt the Bold Contribution Agreement. If approved, the prosed transaction is expected to close shortly thereafter.

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During the first quarter of 2017, our management team focused on the completion of the Bold Contribution Agreement, as well as developing an effective transition plan to effectively integrate operations upon closing.  We plan on running one drilling rig immediately and potentially deploying a second rig toward the end of 2017.

Areas of Operation

Our core areas of operations are in the Midland basin of west Texas, the Eagle Ford trend of south Texas and the Bakken/Three Forks formations of North Dakota.

Our operating results for the three months ended March 31, 2017, were affected by the following factors:

Midland Basin

We own non-operated interests, primarily in Glasscock, Howard, Martin and Midland Counties, Texas. As of March 31, 2017, we had a 39% average working interest in 127 non-operated producing wells. Net daily sales averaged 1,339 BOE per day for the three months ended March 31, 2017. Our Midland basin oil and natural gas properties were acquired in May 2016 as part of the Lynden Arrangement. As such, we had no sales in the prior year period. Closing the Bold Contribution Agreement should significantly supplement production in the Midland basin.

Eagle Ford Trend

We are the owner and operator of leasehold acreage in Fayette, Gonzales and Karnes Counties in the crude oil window of the Eagle Ford shale trend of south Texas. As of March 31, 2017, we were the operator of 89 producing wells in which we owned a 47% average working interest. Additionally we own non-operated interests, primarily in La Salle County. As of March 31, 2017, we had a 12% average working interest in 71 non-operated producing wells. Eagle Ford trend net daily sales averaged 2,355 BOE per day for the three months ended March 31, 2017, down 4% compared to 2,452 BOE per day for the three months ended March 31, 2016. We plan on devoting one drilling rig in our Eagle Ford trend leasehold acreage to drill 11 planned gross wells with an average working interest of 44% during 2017.

Bakken/Three Forks Formations

We own both operated and non-operated interests in the McKenzie County, North Dakota region of the Bakken/Three Forks formations. As of March 31, 2017, we had a 6% average working interest in 158 producing wells. Net daily sales averaged 628 BOE per day for the three months ended March 31, 2017, down 5% compared to 663 BOE per day for the three months ended March 31, 2016.

All Other Properties

As of March 31, 2017, in various other regions, we were the operator of 41 producing wells in which we owned a 67% average working interest. Additionally, we had a 27% average working interest in 98 non-operated producing wells. Net daily sales averaged 413 BOE per day for the three months ended March 31, 2017, down 10% compared to 461 BOE per day for the three months ended March 31, 2016.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting policies are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements

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based on our latest assessment of the current and projected business and general economic environment. There have been no significant changes to our critical accounting policies during the three months ended March 31, 2017.

Results of Operations

Three months ended March 31, 2017, compared to the three months ended March 31, 2016

Oil revenues

For the three months ended March 31, 2017, oil revenues increased by approximately $7.0 million or 126% relative to the comparable period in 2016. Of the increase, approximately $4.5 million was attributable to an increase in our realized price and $2.5 million was attributable to increased volume. Our average realized price per Bbl increased from $27.05 for the three months ended March 31, 2016 to $48.77 or 80% for the three months ended March 31, 2017. We had a net increase in the volume of oil sold of 52 MBbls. The Midland Basin properties we acquired in the Lynden Arrangement provided an additional 67 MBbls, as well as an increase of 2 MBbls related to our Eagle Ford trend properties. This increase was offset by production declines in our Bakken formation properties of 9 MBbls and declines in our remaining properties of 8 MBbls.  

Natural gas revenues

For the three months ended March 31, 2017, natural gas revenues increased by $0.8 million or 80% relative to the comparable period in 2016. Of the increase, approximately $0.4 million was attributable to an increase in our realized price and $0.4 million was attributable to increased volume. Our average realized price per Mcf increased from $1.94 for the three months ended March 31, 2016 to $2.68 or 38% for the three months ended March 31, 2017. The total volume of natural gas produced and sold increased 147 MMcf or 30%, of which 146 MMcf was provided by the Midland Basin properties acquired in the Lynden Arrangement.

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Natural gas liquids revenues

For the three months ended March 31, 2017, natural gas liquids revenues increased by $0.8 million or 245% relative to the comparable period in 2016. Of the increase, approximately $0.4 million was attributable to an increase in our realized price and $0.4 million was attributable to increased volume. The volume of natural gas liquids produced and sold increased by 24 MBbls or 60%. The Midland Basin properties we acquired in the Lynden Arrangement provided 29 MBbls, as well as an increase of 7 MBbls related to our Bakken formation properties. These increases were offset by production declines on our Eagle Ford trend properties of 12 MBbls.

Lease operating expense (“LOE”)

These expenses include all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, re-engineering and workovers, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes and overhead charges provided for in operating agreements.

Total LOE increased by $1.2 million or 37% for the three months ended March 31, 2017 relative to the comparable period in 2016. The increase was primarily the result of the cost to operate the producing assets acquired in the May 2016 Lynden Arrangement that were not present in the prior year period. On a unit-of-production basis, LOE remained relatively flat only increasing 5% per BOE from $9.70 in 2016 to $10.18 in 2017 due to our continued focus on operating costs. Workovers increased to $0.5 million or 83% for the three months ended March 31, 2017 relative to the comparable period in 2016, due to certain wells requiring remedial work such as rod pump replacements to maintain producing levels.

Severance taxes

Severance taxes for the three months ended March 31, 2017 increased by $0.4 million or 107% relative to the comparable period in 2016, primarily due to the increase in oil and natural gas prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained flat and increased by less than 1% due to the mix of production and revenues.

Rig idle expense

We incurred rig idle expenses of $1.3 million during the three months ended March 31, 2016. In late January 2016, we suspended drilling and temporarily idled our contracted drilling rig. Our rig contractor agreed to a reduced daily rate of approximately $20,000 per day while the rig was idled.

Depreciation, depletion and amortization (“DD&A”)

DD&A increased for the three months ended March 31, 2017 by $2.4 million, or 43% relative to the comparable period in 2016, due to the addition of the assets acquired in the Lynden Arrangement to the depletable base, as well as increased production volumes.

General and administrative expense (“G&A”)

These expenses consist primarily of employee remuneration, professional and consulting fees and other overhead expenses. G&A increased by $0.8 million for the three months ended March 31, 2017 relative to the comparable period in 2016. The increase was primarily due to the reimbursement of withholding taxes in relation to the vesting and settlement of RSUs to certain named executive officers that vested during the current period.

Stock-based compensation

Stock-based compensation includes the expense associated with grants of restricted stock units (“RSUs”) to employees and non-employee directors. For the three months ended March 31, 2017, we recognized expense of $1.3 million related to the amortization of the RSU grants. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity-based compensation granted.

Transaction costs

Transaction costs consist primarily of professional and consulting fees associated with the Lynden Arrangement completed on May 18, 2016 and the Bold Contribution Agreement entered on November 7, 2016.

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Interest expense, net

Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense for the three months ended March 31, 2017 was $0.3 million compared to $0.2 million for the comparable period in 2016, due to the issuance of a promissory note.  See Note 9. Long-Term Debt.

Gain on derivative contract, net

For the three months ended March 31, 2017, we recorded a net gain on derivative contracts of $4.5 million, consisting of net realized loss on settlements of $0.5 million offset by unrealized mark-to-market gains of $5.0 million. For the three months ended March 31, 2016, we recorded a net gain on derivative contracts of $0.8 million, consisting of net realized gains on settlements of $2.0 million offset by unrealized mark-to-market losses of $1.2 million.

Income tax benefit

During the three months ended March 31, 2017, we recorded an income tax benefit related to Lynden of $0.04 million as a result of a pre-tax net loss. For the remainder of the Company, we recorded no income tax expense on the pre-tax net income as a result of a full valuation allowance recorded against the net deferred tax asset, as future realization of the net deferred tax asset cannot be assured.

Liquidity and Capital Resources

We expect to finance future acquisition and development activities through available working capital, cash flows from operating activities, possible borrowings under our credit facility, sale of non-strategic assets, various means of corporate and project financing, and assuming we can access the capital markets, the issuance of additional equity securities. In addition, we may continue to partially finance our drilling activities through the sale of participating rights to industry partners or financial institutions, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs.

Bold Contribution Agreement

The anticipated closing of the Bold Contribution Agreement will require additional capital to develop the undeveloped drilling locations. We expect to close the Bold Contribution Agreement in May 2017 and deploy one drilling rig and may attempt to accelerate drilling in the fourth quarter of 2017 by deploying a second drilling rig.  The incremental capital requirements related to Bold Contribution Agreement post-closing activities are expected to be funded by the combined cash flows from operating activities and borrowings from the combined borrowing bases, as well as potential access to capital markets.

Cash Flows from Operating Activities

Substantially all of our cash flows provided by or used in operating activities are derived from and used in the production of our oil, natural gas, and natural gas liquids reserves. We use any excess cash flows to fund our drilling and completion operations and acquisitions of additional mineral leases. Variations in operating cash flows may impact our level of capital expenditures.

Cash flows provided by operating activities for the three months ended March 31, 2017 were $4.4 million compared to cash flows used in operating activities of $15.2 million for the three months ended March 31, 2016. The increase in operating cash flows from the prior period was primarily due to changes in our working capital resulting from increased commodity prices and the producing assets acquired in the Lynden Arrangement. We believe we have sufficient liquidity and capital resources to execute our business plan over the next 12 months and for the foreseeable future.

Cash Flows from Investing Activities

Cash applied to additions to oil and natural gas properties for the three months ended March 31, 2017 and 2016 were $4.2 million and $2.4 million, respectively. Cash applied to additions to oil and natural gas properties in the three months ended March 31, 2017 related primarily to our Lynden properties.

Cash Flows from Financing Activities

Cash flows used in financing activities for the three months ended March 31, 2017 were $0.4 million which consisted of repayments on a promissory note to a drilling contractor.

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We are currently working on securing a new credit facility in conjunction with the close of the Bold Arrangement for which we expect to have a new borrowing base of $150 million. We expect to incur $1 million in fees related to securing the new facility.

Commodity Prices

The up-stream oil and natural gas business has historically been cyclical and we were working in an improved commodity price environment for the three months ended March 31, 2017. Our consolidated average realized prices for the first quarter of 2017 increased approximately 80% for crude oil, 38% for natural gas and 114% for natural gas liquids compared to the comparable period in 2016.  However, as oil revenues represents 82% of our total revenues for the three months ended March 31, 2017, it should be noted that at April 1, 2017, the NYMEX settle price for oil was $50.56 per barrel, down 6% from the December 30, 2016 NYMEX settle price for oil price of $53.72 per barrel, and down 3% from the arithmetic average NYMEX settle price of $51.91 for the three months ended March 31, 2017. If the commodity price environment continues to decline, it would have an adverse impact on our revenues, cash flows, estimated reserves and planned capital expenditures, and could result in impairments of our proved and unproved oil and natural gas properties.

Obligations and Commitments

There have been no changes from the obligations and commitments disclosed in the Obligations and Commitments section of Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2016 Annual Report on Form 10-K.

Environmental Regulations

The Company’s operations are subject to risks normally associated with the exploration for and the production of oil and natural gas, including blowouts, fires, and environmental risks such as oil spills or natural gas leaks that could expose the Company to liabilities associated with these risks.

In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.

However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still accrue to the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.

Recently Issued Accounting Standards

See Note 1. Basis of Presentation and Summary of Significant Accounting Policies in the Notes to Unaudited Condensed Consolidated Financial Statements in this report for discussion of recently issued and adopted accounting standards affecting us.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.

Commodity Price Risk, Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable. Therefore, we use derivative instruments to provide partial protection against declines in oil and natural gas prices and the adverse effect it could have on our financial condition and operations. The types of derivative instruments that we may choose to utilize include costless collars, swaps, and deferred put options. Our hedge objectives may change significantly as our operational profile changes and/or commodities prices change. Currently, we have hedged only a limited amount of our anticipated production beyond 2017 due to low commodity prices. As a consequence, our future performance is subject to increased commodity price risks, and our future cash flows from operations may be subject to further declines if low commodity prices persist. We do not enter into derivative contracts for speculative trading purposes.

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The following is a summary of our open oil and natural gas derivative contracts as of March 31, 2017:

Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $1.1 million at March 31, 2017. Based on the published commodity futures price curves for the underlying commodity as of March 31, 2017, a 10% increase in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to decrease by approximately $4.1 million to a liability of $5.2 million. A 10% decrease in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to increase by approximately $4.1 million to a net asset of $3.0 million. There would also be a similar increase or decrease in Gain on derivative contracts, net in the Consolidated Statements of Operations.

Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and the prime rate based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At March 31, 2017, the principal amount of our long-term debt with our credit facility was $10.0 million and bears interest at rates described in Note 9. Long-Term Debt. Fluctuations in interest rates will cause our annual interest costs to fluctuate. At March 31, 2017, the interest rate on borrowings under our revolving credit facility was 3.084% per year. If these borrowings at March 31, 2017 were to remain constant, a 10% change in interest rates would impact our cash flow by approximately $31,000 per year.

Disclosure of Limitations

Because the information above included only those exposures that existed at March 31, 2017, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during future periods.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Securities Exchange Act of 1934 (the Exchange Act”) Rules 13a-15(e) and 15d-15(e), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our [Principal Accounting Officer], of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and [Principal Accounting Officer] concluded that our disclosure controls and procedures were effective as of March 31, 2017 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and  [Principal Accounting Officer], as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we may be involved in various legal proceedings and claims in the ordinary course of business. As of March 31, 2017, and through the filing date of this report, we do not believe the ultimate resolution of any such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or results of operations.  

See Note 12. Commitments and Contingencies in the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this report, which is incorporated herein by reference, for material matters that have arisen since the filing of our Annual Report on Form 10-K for the year ended December 31, 2016.

Item 1A. Risk Factors

There has been no changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2016.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information.

None.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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INDEX TO EXHIBITS

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