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EX-31.1 - EX-31.1 - EARTHSTONE ENERGY INCeste-ex311_8.htm
EX-32.1 - EX-32.1 - EARTHSTONE ENERGY INCeste-ex321_6.htm
EX-31.2 - EX-31.2 - EARTHSTONE ENERGY INCeste-ex312_9.htm
EX-32.2 - EX-32.2 - EARTHSTONE ENERGY INCeste-ex322_7.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

þ

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2016

Or

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-35049  

 

EARTHSTONE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

84-0592823

(State or other jurisdiction

 

(I.R.S Employer

of incorporation or organization)

 

Identification No.)

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  þ    No  o

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  þ    No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

o

 

Accelerated filer

 

þ

 

 

 

 

 

 

 

Non-accelerated filer

 

o  (Do not check if a smaller reporting company)

 

Smaller reporting company

 

o

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

As of May 4, 2016, 13,835,128 shares of common stock, $0.001 par value per share, were outstanding.

 

 

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

Page

 

 

 

 

 

 

 

PART I – FINANCIAL INFORMATION

 

 

 

 

 

 

 

Item 1.

 

Financial Statements (unaudited)

 

5

 

 

Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015

 

5

 

 

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015

 

6

 

 

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015

 

7

 

 

Notes to Unaudited Condensed Consolidated Financial Statements

 

8

Item 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

16

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

23

Item 4.

 

Controls and Procedures

 

24

 

 

 

 

 

 

 

PART II – OTHER INFORMATION

 

 

 

 

 

 

 

Item 1.

 

Legal Proceedings

 

25

Item 1A.

 

Risk Factors

 

25

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

25

Item 3.

 

Defaults Upon Senior Securities

 

25

Item 4.

 

Mine Safety Disclosures

 

25

Item 5.

 

Other Information

 

25

Item 6.

 

Exhibits

 

25

 

 

Signatures

 

26

 

 

 

2


 

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section included in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2015, and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

 

·

volatility and weakness in commodity prices for oil and natural gas and the effect of prices set or influenced by action of the Organization of Petroleum Exporting Countries (“OPEC”);

 

·

substantial changes in estimates of our proved reserves;

 

·

substantial declines in the values of our oil and natural gas reserves;

 

·

our ability to replace our oil and natural gas reserves;

 

·

the potential for production decline rates for our wells to be greater than we expect;

 

·

the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves; 

 

·

the ability and willingness of our partners under our joint operating agreements to join in our future exploration, development and production activities;

 

·

our ability to acquire leases and quality services and supplies on a timely basis and at reasonable prices;

 

·

the cost and availability of high quality goods and services with fully trained and adequate personnel, such as drilling rigs and completion equipment;

 

·

risks in connection with potential acquisitions and the integration of significant acquisitions;

 

·

the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management’s time and energy;

 

·

the possibility that anticipated divestitures may not occur or could be burdened with unforeseen costs;

 

·

reductions in the borrowing base under our credit facility;

 

·

risks incident to the drilling and operation of oil and natural gas wells;

 

·

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

 

·

the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices;

 

·

significant competition for acreage and acquisitions;

 

·

the effect of existing and future laws, governmental regulations and the political and economic climates of the United States;

 

·

our ability to retain key members of senior management and key technical and financial employees;

 

·

changes in environmental laws and the regulation and enforcement related to those laws;

 

·

the identification of and severity of environmental events and governmental responses to these or other environmental events;

 

·

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulations, derivatives reform, and changes in state, and federal income taxes;

3


 

 

·

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we conduct  business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets will be disrupted or unavailable; 

 

·

social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as Africa, the Middle East, and armed conflict or acts of terrorism or sabotage;

 

·

the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;

 

·

other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

 

·

the effect of our oil and natural gas derivative activities;

 

·

title to the properties in which we have an interest may be impaired by title defects; and

 

·

our dependency on the skill, ability and decisions of third party operators of oil and natural gas properties in which we have a non-operated working interest.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

4


 

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

 

 

 

March 31,

 

 

December 31,

 

ASSETS

 

2016

 

 

2015

 

Current assets:

 

(In thousands, except share amounts)

 

Cash and cash equivalents

 

$

5,684

 

 

$

23,264

 

Accounts receivable:

 

 

 

 

 

 

 

 

Oil, natural gas, and natural gas liquids revenues

 

 

12,161

 

 

 

13,529

 

Joint interest billings and other

 

 

3,034

 

 

 

4,924

 

Current derivative assets

 

 

2,460

 

 

 

3,694

 

Prepaid expenses and other current assets

 

 

721

 

 

 

498

 

Total current assets

 

 

24,060

 

 

 

45,909

 

Oil and gas properties, successful efforts method:

 

 

 

 

 

 

 

 

Proved properties

 

 

287,683

 

 

 

283,644

 

Unproved properties

 

 

32,926

 

 

 

34,609

 

Total oil and gas properties

 

 

320,609

 

 

 

318,253

 

 

 

 

 

 

 

 

 

 

Accumulated depreciation, depletion, and amortization

 

 

(125,294

)

 

 

(119,920

)

Net oil and gas properties

 

 

195,315

 

 

 

198,333

 

Other noncurrent assets:

 

 

 

 

 

 

 

 

Goodwill

 

 

17,532

 

 

 

17,532

 

Office and other equipment, less accumulated depreciation of $1,174 and $1,028 at

   March 31, 2016 and December 31, 2015

 

 

1,808

 

 

 

1,934

 

Other noncurrent assets

 

 

1,192

 

 

 

1,236

 

Noncurrent derivative assets

 

 

7

 

 

 

 

TOTAL ASSETS

 

$

239,914

 

 

$

264,944

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

Accounts payable

 

$

11,381

 

 

$

11,580

 

Accrued expenses

 

 

8,598

 

 

 

12,975

 

Revenues and royalties payable

 

 

5,672

 

 

 

8,576

 

Advances

 

 

4,213

 

 

 

15,447

 

Total current liabilities

 

 

29,864

 

 

 

48,578

 

 

 

 

 

 

 

 

 

 

Noncurrent liabilities:

 

 

 

 

 

 

 

 

Long-term debt

 

 

11,191

 

 

 

11,191

 

Asset retirement obligations

 

 

5,195

 

 

 

5,075

 

Other noncurrent liabilities

 

 

212

 

 

 

227

 

Total noncurrent liabilities

 

 

16,598

 

 

 

16,493

 

 

 

 

 

 

 

 

 

 

Total liabilities

 

 

46,462

 

 

 

65,071

 

 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 9)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

 

 

 

Preferred stock, $0.001 par value, 20,000,000 shares authorized;

   none issued or outstanding

 

 

 

 

 

 

Common stock, $0.001 par value, 100,000,000 shares authorized; 13,835,128 shares

   issued and outstanding at March 31, 2016 and December 31, 2015

 

 

14

 

 

 

14

 

Additional paid-in capital

 

 

358,086

 

 

 

358,086

 

Accumulated deficit

 

 

(164,188

)

 

 

(157,767

)

Treasury stock, 15,357 shares at March 31, 2016 and December 31, 2015

 

 

(460

)

 

 

(460

)

Total equity

 

 

193,452

 

 

 

199,873

 

 

 

 

 

 

 

 

 

 

TOTAL LIABILITIES AND EQUITY

 

$

239,914

 

 

$

264,944

 

 

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

5


 

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

Three months ended March 31,

 

 

 

2016

 

 

2015

 

REVENUES

 

(In thousands, except share and per share amounts)

 

Oil, natural gas, and natural gas liquids revenues:

 

 

 

 

 

 

 

 

Oil

 

$

5,539

 

 

$

9,038

 

Natural gas

 

 

943

 

 

 

1,530

 

Natural gas liquids

 

 

328

 

 

 

674

 

Total oil, natural gas, and natural gas liquids revenues

 

 

6,810

 

 

 

11,242

 

Gathering income

 

 

54

 

 

 

78

 

Total revenues

 

 

6,864

 

 

 

11,320

 

OPERATING COSTS AND EXPENSES

 

 

 

 

 

 

 

 

Production costs:

 

 

 

 

 

 

 

 

Lease operating expense

 

 

3,066

 

 

 

4,374

 

Severance taxes

 

 

382

 

 

 

630

 

Rig idle expense

 

 

1,269

 

 

 

 

Depreciation, depletion, and amortization

 

 

5,505

 

 

 

5,924

 

Re-engineering and workovers

 

 

275

 

 

 

119

 

Exploration expense

 

 

5

 

 

 

 

General and administrative expense

 

 

3,198

 

 

 

2,571

 

Total operating costs and expenses

 

 

13,700

 

 

 

13,618

 

Loss from operations

 

 

(6,836

)

 

 

(2,298

)

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(223

)

 

 

(169

)

Net gain on derivative contracts

 

 

765

 

 

 

674

 

Other (expense) income, net

 

 

(127

)

 

 

94

 

Total other income (expense)

 

 

415

 

 

 

599

 

Loss before income taxes

 

 

(6,421

)

 

 

(1,699

)

Income tax expense (benefit)

 

 

 

 

 

(585

)

Net loss

 

$

(6,421

)

 

$

(1,114

)

Net loss per common share:

 

 

 

 

 

 

 

 

Basic

 

$

(0.46

)

 

$

(0.08

)

Diluted

 

$

(0.46

)

 

$

(0.08

)

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

Basic

 

 

13,858,128

 

 

 

13,858,128

 

Diluted

 

 

13,858,128

 

 

 

13,858,128

 

 

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

6


 

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

Three months ended March 31,

 

 

 

2016

 

 

2015

 

Cash flows from operating activities:

 

(In thousands)

 

Net loss

 

$

(6,421

)

 

$

(1,114

)

Adjustments to reconcile net loss to net cash provided by

   operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

 

5,505

 

 

 

5,924

 

Unrealized loss on derivative contracts

 

 

1,226

 

 

 

820

 

Accretion of asset retirement obligations

 

 

128

 

 

 

145

 

Deferred income taxes

 

 

 

 

 

(585

)

Amortization of deferred financing costs

 

 

70

 

 

 

65

 

Settlement of asset retirement obligations

 

 

 

 

 

(46

)

Changes in assets and liabilities:

 

 

 

 

 

 

 

 

Decrease in accounts receivable

 

 

3,258

 

 

 

7,754

 

(Increase) decrease in prepaid expenses and other

 

 

(244

)

 

 

387

 

Decrease in accounts payable and accrued expenses

 

 

(4,576

)

 

 

(21,690

)

Decrease in revenue and royalties payable

 

 

(2,904

)

 

 

(8,730

)

Decrease in advances

 

 

(11,234

)

 

 

(4,436

)

Net cash used in operating activities

 

 

(15,192

)

 

 

(21,506

)

Cash flows from investing activities:

 

 

 

 

 

 

 

 

Additions to oil and gas property and equipment

 

 

(2,365

)

 

 

(19,040

)

Additions to other property and equipment

 

 

(20

)

 

 

(138

)

Net cash used in investing activities

 

 

(2,385

)

 

 

(19,178

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

Deferred financing costs

 

 

(3

)

 

 

(73

)

Net cash used in financing activities

 

 

(3

)

 

 

(73

)

Net decrease in cash and cash equivalents

 

 

(17,580

)

 

 

(40,757

)

Cash and cash equivalents at beginning of period

 

 

23,264

 

 

 

100,447

 

Cash and cash equivalents at end of period

 

$

5,684

 

 

$

59,690

 

Supplemental disclosure of cash flow information

 

 

 

 

 

 

 

 

Cash paid for:

 

 

 

 

 

 

 

 

Interest

 

$

142

 

 

$

52

 

Non-cash investing and financing activities:

 

 

 

 

 

 

 

 

Asset retirement obligations

 

$

(8

)

 

$

43

 

 

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

 

 

 

7


 

EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1. Basis of Presentation

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” or the “Company”) is an independent oil and gas exploration and production company focused on the acquisition, development, exploration and production of onshore, crude oil and natural gas reserves, with a current focus on the Eagle Ford trend of south Texas and the Williston Basin of North Dakota and Montana.

The accompanying Unaudited Condensed Consolidated Financial Statements of Earthstone and our wholly-owned subsidiaries, which we refer to as “we,” “our” or “us,” have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial statements. 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, 2015 is derived from the audited consolidated financial statements at that date.

The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. For further information, see Note 2 in the Notes to Consolidated Financial Statements contained in our Annual Report on Form 10-K for the year ended December 31, 2015 (the “2015 Form 10-K”).

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP, has been condensed or omitted. These financial statements should be read in conjunction with the 2015 Form 10-K, and the Company’s other filings with the SEC.  The Company has evaluated events or transactions through the date of issuance of these Unaudited Condensed Consolidated Financial Statements.

Recently Adopted and Issued Accounting Standards

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (“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 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 will 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.

Debt Issuance Costs – In April 2015, the FASB issued updated guidance which changes the presentation of debt issuance costs in the financial statements.  Under this updated guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset.  Amortization of the costs is reported as interest expense.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  The Company adopted this standards update, as required, effective January 1, 2016.  The adoption of this standards update did not affect the Company’s method of amortizing debt issuance costs and did not have a material impact on its Condensed Consolidated Financial Statements.  

Measurement-Period Adjustments – In September 2015, the FASB issued updated guidance that eliminates the requirement to restate prior periods to reflect adjustments made to provisional amounts recognized in a business combination.  The updated guidance requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.  The standards update is effective prospectively for interim and annual periods beginning after December 15, 2015, with early adoption permitted.  The Company adopted this standard update, as required, effective January 1, 2016, which did not have a material impact on its Condensed Consolidated Financial Statements.  

8


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Leases – In February 2016, the FASB issued updated guidance on accounting for leases.  This 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 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 will 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.

 

 

Note 2. Acquisitions and Divestitures

In June 2015, the Company acquired a 50% operated working interest in approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production, from two gross Austin Chalk wells with gross production of 44 barrels of oil equivalent per day as of the time of acquisition. The Gonzales County acreage is expected to provide for 13 gross Eagle Ford locations.

Also during June 2015, the Company acquired 400 gross acres in northern Karnes County, Texas, which is adjacent to the 1,000 gross acre in southern Gonzales County, Texas.  Subsequent trades in Karnes County reduced the gross acreage from 400 gross acres to 350 gross acres (117 net acres) which has allowed for longer laterals and more efficient development.  The Company initiated drilling on this acreage during the fourth quarter of 2015, with the completion of the four wells expected during the second half of 2016.

The following table summarizes the consideration paid to acquire the properties and the estimated fair values of the assets acquired and liabilities assumed (in thousands):

 

Purchase price

 

$

4,066

 

Estimated fair value of assets acquired:

 

 

 

 

Proved oil and natural gas properties

 

$

588

 

Unproved oil and natural gas properties

 

 

3,496

 

Total assets acquired

 

$

4,084

 

Estimated fair value of liabilities assumed:

 

 

 

 

Asset retirement obligations

 

$

13

 

Other liabilities

 

 

5

 

Total liabilities assumed

 

$

18

 

Consideration paid

 

$

4,066

 

 

Pro forma financial information, assuming the acquisition occurred at the beginning of each period presented, has not been presented because the effect on the Company’s results for each of those periods is not material.  The results of the above acquisitions have been included in the Company’s Condensed Consolidated Financial Statements since the date of each acquisition.

In June 2015, the Company acquired additional acreage and increased the Company’s working interest in wells in existing Bakken spacing units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells. The acquisition included 164 net acres which allowed the Company to increase its working interest in approximately 41 producing wells and 21 wells that are in the drilling and completion phase.

In August 2015, the Company acquired a 33% working interest in approximately 1,650 gross acres, in southern Gonzales County, Texas for $3.3 million. This acreage is anticipated to support 16 additional gross Eagle Ford locations.  

Divestitures

In April 2015, the Company sold substantially all of its Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million, recording a gain of $1.6 million.  The effective date of the transaction was March 1, 2015.

9


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

 

 

Note 3. Derivative Financial Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815 Derivatives and Hedging (“ASC Topic 815”), to account for its derivative financial instruments. The Company does not enter into derivative contracts for speculative trading purposes. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The Company did not post collateral under any of these contracts.

The Company’s crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain on derivative contracts” on the Condensed Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and are included in the Condensed Consolidated Balance Sheets as assets or liabilities.

With an individual derivative counterparty, the Company may have multiple hedge positions that expire at various points in the future and result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity, and the netted balance is reflected in the Condensed Consolidated Balance Sheets as an asset or a liability.

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, 2016:

 

Period

 

Instrument

 

Commodity

 

Volume in

MMBtu / Bbls

 

 

Fixed Price

 

April 2016 - March 2017

 

Swap

 

Crude Oil

 

 

60,000

 

 

$

42.30

 

April 2016 - March 2017

 

Swap

 

Crude Oil

 

 

60,000

 

 

$

42.30

 

April 2016 - June 2016

 

Swap

 

Crude Oil

 

 

30,000

 

 

$

58.00

 

April 2016 - December 2016

 

Swap

 

Crude Oil

 

 

45,000

 

 

$

60.80

 

April 2016 - December 2016

 

Swap

 

Crude Oil

 

 

45,000

 

 

$

60.80

 

April 2016 - December 2016

 

Swap

 

Natural Gas

 

 

630,000

 

 

$

2.530

 

January 2017 - December 2017

 

Swap

 

Natural Gas

 

 

480,000

 

 

$

2.785

 

 

 

In April 2016, the Company entered in the following commodity derivative contracts:

 

Period

 

Instrument

 

Commodity

 

Volume in

MMBtu / Bbls

 

 

Fixed Price

 

May 2016 - December 2016

 

Swap

 

Crude Oil

 

 

80,000

 

 

45.17

 

January 2017 - December 2017

 

Swap

 

Crude Oil

 

 

120,000

 

 

46.75

 

May 2016 - December 2016

 

Swap

 

Natural Gas

 

 

80,000

 

 

 

2.380

 

January 2017 - December 2017

 

Swap

 

Natural Gas

 

 

240,000

 

 

 

2.860

 

 

 

10


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

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):

 

 

 

 

 

March 31, 2016

 

 

December 31, 2015

 

Derivatives not

designated as hedging

contracts under ASC

Topic 815

 

Balance Sheet Location

 

Gross

Recognized

Assets /

Liabilities

 

 

Gross

Amounts

Offset

 

 

Net

Recognized

Assets /

Liabilities

 

 

Gross

Recognized

Assets /

Liabilities

 

 

Gross

Amounts

Offset

 

 

Net

Recognized

Assets /

Liabilities

 

Commodity contracts

 

Current derivative assets

 

$

2,460

 

 

$

 

 

$

2,460

 

 

$

3,694

 

 

$

 

 

$

3,694

 

Commodity contracts

 

Noncurrent derivative assets

 

$

7

 

 

$

 

 

$

7

 

 

$

 

 

$

 

 

$

 

 

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

 

 

 

 

 

Three months ended March 31,

 

Derivatives not designated as hedging contracts under ASC Topic 815

 

Statement of Operations Location

 

2016

 

 

2015

 

Unrealized loss on commodity contracts

 

Net gain on derivative contracts

 

$

(1,226

)

 

$

(820

)

Realized gain on commodity contracts

 

Net gain on derivative contracts

 

$

1,991

 

 

$

1,494

 

 

 

 

 

$

765

 

 

$

674

 

 

 

Note 4. Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosure (“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 Topic 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 Topic 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, 2016.

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 Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy.

11


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

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 Condensed Consolidated Financial Statements.

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

 

March 31, 2016

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

Financial assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current derivative assets

 

$

 

 

$

2,460

 

 

$

 

 

$

2,460

 

Noncurrent derivative assets

 

 

 

 

 

7

 

 

 

 

 

 

7

 

Total financial assets

 

$

 

 

$

2,467

 

 

$

 

 

$

2,467

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current derivative assets

 

$

 

 

$

3,694

 

 

$

 

 

$

3,694

 

Total financial assets

 

$

 

 

$

3,694

 

 

$

 

 

$

3,694

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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. 

 

The Company did not recognize any impairment write-downs with respect to its oil and natural gas properties or goodwill during the three months ended March 31, 2016 or 2015.

 

 

Note 5. Earnings (Loss) Per Common Share

Basic earnings (loss) per share is computed by dividing net income (loss) attributable to shares of Common Stock by the basic weighted-average shares of Common Stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents. Common stock equivalents include awards issued under the Company’s long-term incentive plan.  The Company had no outstanding common stock equivalents for the three months ended March 31, 2016 and 2015.

 

The following table is a reconciliation of net income and weighted-average shares of Common Stock outstanding for purposes of calculating basic and diluted income per share:

 

 

 

Three months ended March 31,

 

(In thousands, except share and per share amounts)

 

2016

 

 

2015

 

Net loss

 

$

(6,421

)

 

$

(1,114

)

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

Basic

 

 

13,858,128

 

 

 

13,858,128

 

Diluted

 

 

13,858,128

 

 

 

13,858,128

 

Net loss per common share:

 

 

 

 

 

 

 

 

Basic

 

$

(0.46

)

 

$

(0.08

)

Diluted

 

$

(0.46

)

 

$

(0.08

)

 

 

12


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

Note 6. Long-Term Debt

In December 2014, the Company entered into a credit agreement providing for a $500.0 million four-year senior secured revolving credit facility.  The current borrowing base under the credit agreement is $80.0 million and is subject to redetermination during May and November of each year. As of March 31, 2016, 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 1.00% to 1.75% for base rate loans and from 2.00% to 2.75% 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 facility 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, 2016, the Company had an $80.0 million borrowing base, with $11.2 million of debt outstanding, (bearing an interest rate of 2.442%), $0.2 million of letters of credit outstanding, resulting in $68.6 million of borrowing base availability under its credit facility.

The credit facility 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 period.  As of March 31, 2016 and December 31, 2015, the Company was in compliance with these covenants under the credit facility.

Interest expense for the three months ended March 31, 2016 and 2015, includes amortization of deferred financing costs of $70,000 and $65,000, respectively. As of March 31, 2016 and December 31, 2015, $0.8 million of costs, net of amortization, associated with the credit facility have been capitalized.  These costs are amortized on a straight-line basis over the term of the credit agreement.  

 

 

Note 7. Asset Retirement Obligations

The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. The accretion of the asset retirement obligation is included in “Lease operating expense” in the Condensed Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and/or the discount rate.

The following table summarizes the Company’s asset retirement obligation transactions recorded during the three months ended March 31, 2016, and in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (in thousands):

 

 

 

2016

 

Asset retirement obligations at December 31, 2015

 

$

5,075

 

Liabilities incurred

 

 

4

 

Accretion expense

 

 

128

 

Property dispositions

 

 

 

Liabilities settled

 

 

 

Revision of estimates

 

 

(12

)

Asset retirement obligations at March 31, 2016

 

$

5,195

 

 

 

Note 8. Income Taxes

For the three months ended March 31, 2016, the Company recorded no income tax expense or benefit because property impairments recorded during the year ended December 31, 2015 reduced the book value of the Company’s properties below their tax basis requiring the Company to record a net deferred tax asset.  Because the future realization of this deferred tax asset could not be assured, the Company recorded a 100% valuation allowance against its deferred tax asset. The pre-tax loss recorded for the three months ended March 31, 2016, increased the Company’s net deferred tax asset but did not result in a recognized tax benefit because the realization

13


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

of the Company’s net tax asset still cannot be assured, therefore the valuation allowance also was increased and offset the tax benefit that would have resulted from the net operating loss. For the three month period ended March 31, 2015, the Company recorded an income tax benefit of $0.6 million. The effective tax rate was 34.4% which included approximately 0.4% of the estimated portion of the Company’s income subject to income tax in the states in which the Company operates.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the Condensed Consolidated Financial Statements in accordance with FASB ASC Topic 740, Income Taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax asset will be realized. The ultimate realization of deferred income tax assets, if any, is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.

 

 

Note 9. Commitments and Contingencies

In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation.

Commitments

In 2014, the Company entered into an 18 month drilling contract to utilize a newly-built drilling rig in its drilling operations.  The new rig was an upgrade and replacement of a rig with a drilling contract that was expiring.  The new contract commenced upon delivery of the rig in April 2015.  The contract provides for a daily drilling rate of approximately $29,000.  In January 2016, the Company suspended drilling and temporarily idled the drilling rig.  The Company’s rig contractor agreed to a reduced daily rate of approximately $20,000 per day while the rig is idled.  If the Company chooses to recommence drilling with this rig, the daily drilling rate of approximately $29,000 per day will resume.  Should the Company decide to permanently suspend drilling with this rig, a termination fee will be due immediately.    As of March 31, 2016, the remaining commitment on this contract is approximately $3.9 million.             

As a part of the 2013 Eagle Ford Acquisition, the Company and its primary working interest partner in the area ratified several long-term natural gas purchasing and natural gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company and its primary working interest partner have a volume commitment, whereby the owner of the pipeline is paid a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity. Since the time of the acquisition, the volume commitment has not been met. The rate and terms under this purchasing and processing contract expire on June 1, 2021.  As of March 31, 2016, the Company’s share of the remaining commitment on this contract is approximately $4.3 million.

Contingencies

Environmental

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.

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 125th Judicial District Court of Harris

14


EARTHSTONE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

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

 

 

 

15


 

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

The following discussion of our financial condition, results of operations, liquidity and capital resources should be read together with our Unaudited Condensed Consolidated Financial Statements and notes to Unaudited Condensed Consolidated Financial Statements contained in this report as well as our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Unless the context otherwise requires, the terms “the Company,” “our,” “we,” “us,” and “Earthstone” refer to Earthstone Energy, Inc. and its consolidated subsidiaries.

Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, including those discussed below, which cause actual results to differ from those expressed.  For more information, see “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

We are a growth-oriented independent oil and gas company engaged in the development and acquisition of oil and gas reserves through an active and diversified program that includes the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions, and exploration activities, with our current primary assets located in the Eagle Ford trend of South Texas and in the Williston Basin of North Dakota.   Future growth in assets, earnings, cash flows and share values will be dependent upon our ability to acquire, discover and develop commercial quantities of oil and natural gas reserves that can be produced at a profit, and assemble an oil and natural gas reserve base with a market value exceeding its acquisition, development and production costs.   Our strategy includes a combination of acquisition, development and exploration activities, typically in more than one basin. Historically, we have shifted our emphasis among these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our acreage positions in the Eagle Ford trend of south Texas and in the Williston Basin of North Dakota. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so that we have the potential to economically replace our production and increase our proved reserves.

For 2016, it is our intent to conduct our operations within our available cash flows. To that end, we have temporarily suspended drilling and completion operations and, in relation to general and administrative costs, we reduced our head count and salaries. Generally, employee base salaries have been reduced 10% and we have reduced certain benefits.  Further, we do not intend to pay cash bonuses during 2016. Our actions are in direct response to continuing low commodity prices. While we believe we have made appropriate adjustments, we have also maintained a positive corporate culture and retained an outstanding staff.  While conducting operations within available cash flow, we will continue to pursue our business strategy.   Following is a brief outline of our current plans:

 

·

pursue attractive asset or corporate acquisitions;

 

·

maintain and  expand our acreage positions and drilling inventory;

 

·

pending adequate commodity prices continue the development of our acreage positions in the Eagle Ford trend of south Texas and in the Williston Basin of North Dakota; and

 

·

generate additional exploration and development projects; and

 

·

obtain additional capital as available and needed, or utilize our common stock for acquisitions.

Commodity Prices:

The upstream oil and natural gas business is cyclical and we are currently operating in a sustained low commodity price environment. Our consolidated average realized prices for the first quarter of 2016 decreased 38% for crude oil, 29% for natural gas and 44% for natural gas liquids compared with the same quarter in 2015. These low prices resulted in a reduction in our capital spending program, had significant negative impacts on our revenues, profitability, cash flows and proved reserves, resulted in asset and goodwill impairments at the end of 2015, and caused us to execute certain cost saving organizational changes.

Thus far in 2016, commodity prices have continued to trade in a low range, with crude oil prices falling during the first quarter below $30.00 per barrel on some occasions. If the industry downturn continues for an extended period, or becomes more severe, we could experience additional material negative impacts on our revenues, profitability, cash flows, liquidity, and reserves, and we could consider further reductions in our capital program.  Our production could decline further as a result of these activities.

16


 

Acquisitions and Divestitures:

In April 2015, we sold substantially all of our Louisiana properties located primarily in DeSoto and Caddo Parishes for cash consideration of $3.4 million, recording a gain of $1.6 million.  The effective date of the transaction was March 1, 2015.

In June 2015, we acquired a 50% operated working interest in approximately 1,000 gross acres in southern Gonzales County, Texas. The acreage, acquired for future Eagle Ford development, is 100% held-by-production from two gross Austin Chalk wells with gross production of 44 barrels of oil per day as of the time of acquisition.  This acreage position is expected to provide for 13 gross Eagle Ford locations.

 

Also during June 2015, we acquired 400 gross acres in northern Karnes County, Texas, which is adjacent to our 1,000 gross acres in southern Gonzales County, Texas.  Subsequent trades in Karnes County reduced the gross acreage from 400 gross acres to 350 gross acres (117 net acres) which has allowed for longer laterals and more efficient development.  We initiated drilling on this acreage during the fourth quarter of 2015, with completion of the four wells expected during the second half of 2016.

In June 2015, we acquired additional acreage and increased our working interest in wells in existing Bakken units primarily located in the Banks Field of McKenzie County, North Dakota, for $1.4 million plus purchase price adjustments of $2.0 million for the revenues, net of production taxes and operating expenses and capital costs incurred for the existing wells.  The acquisition included 164 net acres which allowed us to increase our working interest in approximately 41 producing wells and 21 wells that in the drilling and completion phase.

In August 2015, we acquired a 33% working interest in approximately 1,650 gross acres, in southern Gonzales County, Texas for $3.3 million. This acreage supports 16 additional gross Eagle Ford locations.  

On December 16, 2015, we entered into an Arrangement Agreement (the “Arrangement Agreement”), among Lynden Energy Corp., a company existing under the laws of British Columbia, Canada (“Lynden”), Earthstone and 1058286 B.C. Ltd., a company exiting under the laws of British Columbia, Canada and our wholly-owned subsidiary (“Merger Sub”), pursuant to which Merger Sub will acquire all of the outstanding shares of common stock of Lynden (the “Lynden Shares”) and as an integral part of such acquisition, Merger Sub and Lynden will amalgamate to continue as one corporate entity with Lynden surviving the amalgamation as part of a plan of arrangement (the “Transaction”).   Under the Arrangement Agreement, the terms of which were unanimously approved by our Boards of Directors, Lynden and Merger Sub, we will issue approximately 3.7 million shares of our common stock, (“Earthstone Common Stock”), to Lynden stockholders.

Under the Arrangement Agreement, Lynden stockholders will receive 0.02842 shares of Earthstone Common Stock in exchange for each share of Lynden common stock held.  Following the Transaction, stockholders of Earthstone and Lynden are expected to own approximately 79% and 21%, respectively, of the combined company on a fully diluted basis. We expect the transaction to close during the second quarter of 2016.

17


 

Results of Operations

Three months ended March 31, 2016, compared to the three months ended March 31, 2015

Sales and Other Operating Revenues

The quantities of oil, natural gas, and natural gas liquids produced and sold, the average sales price per unit sold and our related revenues, exclusive of settlements related to derivative contracts for the three months ended March 31, 2016 and 2015, are presented below:

 

 

 

Three months ended March 31,

 

 

 

 

 

 

 

2016

 

 

2015

 

 

Change

 

Sales volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

 

205

 

 

 

208

 

 

 

(3

)

Natural gas (MMcf)

 

 

485

 

 

 

558

 

 

 

(73

)

Natural gas liquids (MBbl)

 

 

40

 

 

 

45

 

 

 

(5

)

Barrels of oil equivalent (MBOE)  (1)

 

 

325

 

 

 

346

 

 

 

(21

)

Barrels of oil equivalent per day (BOEPD) (1)

 

 

3,576

 

 

 

3,849

 

 

 

(273

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices realized: (2)

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbl)

 

$

27.05

 

 

$

43.44

 

 

$

(16.39

)

Natural gas (Mcf)

 

$

1.94

 

 

$

2.74

 

 

$

(0.80

)

Natural gas liquids (Bbl)

 

$

8.26

 

 

$

14.85

 

 

$

(6.59

)

 

 

 

Three months ended March 31,

 

 

 

 

 

(In thousands)

 

2016

 

 

2015

 

 

Change

 

Oil, natural gas, and natural gas liquids revenues:

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

5,539

 

 

$

9,038

 

 

$

(3,499

)

Natural gas

 

 

943

 

 

 

1,530

 

 

 

(587

)

Natural gas liquids

 

 

328

 

 

 

674

 

 

 

(346

)

Other operating revenues:

 

 

 

 

 

 

 

 

 

 

 

 

Gathering income

 

 

54

 

 

 

78

 

 

 

(24

)

Total revenues

 

$

6,864

 

 

$

11,320

 

 

$

(4,456

)

 

(1)

Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equals one barrel of oil equivalent (BOE). This ratio does not assume price equivalency and, given price differentials, the price per barrel of oil equivalent for natural gas and natural gas liquids may differ significantly from the price for a barrel of oil.

(2)

Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting. Our derivatives have been marked-to-market through our Unaudited Condensed Consolidated Statements of Operations as other income/expense: which means that all our realized gains/losses on these derivatives are reported in other income/expense. For further information see the Net Gain on Derivative Contracts discussed below.  

Sales of Oil

For the three months ended March 31, 2016, oil revenues decreased by $3.5 million or 39% relative to the comparable period in 2015. The decrease was principally attributable to a decrease in our realized price. The average realized price per Bbl decreased from $43.44 to $27.05 or 38%. The volume of oil sales was relatively flat decreasing by only 3 MBbls; due to normal production declines on our operated Eagle Ford and non-operated Bakken-Three Forks properties, nearly offset by production from new Eagle Ford wells drilled and completed after the first quarter 2015 and additional interests purchased in our Bakken-Three Forks property.

18


 

Sales of Natural Gas

Natural gas revenues decreased by $0.6 million or 38%. Of the decrease, $0.2 million was attributable to decreased volume and $0.4 million was attributable to the decline in our realized price. Our average realized price per Mcf decreased from $2.74 to $1.94 or 29%. The volume of natural gas produced and sold decreased by 73 MMcf; our operated Eagle Ford property remained relatively flat; our non-operated Eagle Ford property decreased by 53 MMcf; and our non-operated Bakken-Three Forks assets decreased by 11 MMcf. Also contributing to the decrease was the loss of 32 MMcf from our Louisiana properties that were sold effective March 1, 2015. These declines were offset by increases on our east Texas and Oklahoma properties of 18 MMcf and 9 MMcf, respectively. The remaining 4 MMcf decrease was due to production declines and variability in sales volumes in our conventional properties mainly in Texas.  

Sales of Natural Gas Liquids

Natural gas liquids revenues decreased by $0.3 million or 51%, attributable primarily to a decrease in our realized price. The average realized price per Bbl decreased from $14.85 to $8.26 or 44%. The volume of natural gas liquids sales produced and sold was relatively flat decreasing by only 5 MBbls; the slight decrease was due to declines on our non-operated Eagle Ford property and non-operated assets in the Bakken-Three Forks area.

Production Costs

Our production costs for the three months ended March 31, 2016 and 2015 are summarized in the table below:

 

 

 

Three months ended March 31,

 

 

 

 

 

(In thousands)

 

2016

 

 

2015

 

 

Change

 

Lease operating expenses

 

$

3,066

 

 

$

4,374

 

 

$

(1,308

)

Severance taxes

 

$

382

 

 

$

630

 

 

$

(248

)

Re-engineering and workover expenses

 

$

275

 

 

$

119

 

 

$

156

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LOE per BOE*

 

$

8.57

 

 

$

11.83

 

 

$

(3.26

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Severance tax as a percent of oil, natural gas and natural

   gas liquids revenues

 

 

5.61

%

 

 

5.60

%

 

 

0.01

%

 

*

Excludes ad valorem tax and accretion expense related to our asset retirement obligations.

Lease Operating Expenses

Lease operating expenses (“LOE”) includes 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, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges from other operators provided for in operating agreements.

 

 

 

Three months ended March 31,

 

 

 

 

 

(In thousands)

 

2016

 

 

2015

 

 

Change