ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
EV Energy Partners, L.P.
Condensed Consolidated Balance Sheets
(In thousands, except number of units)
(Unaudited)
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,552
|
|
|
$
|
5,557
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids revenues
|
|
|
44,762
|
|
|
|
39,629
|
|
Related party
|
|
|
7,152
|
|
|
|
745
|
|
Other
|
|
|
1,046
|
|
|
|
2,451
|
|
Derivative asset
|
|
|
1,993
|
|
|
|
201
|
|
Other current assets
|
|
|
3,295
|
|
|
|
3,718
|
|
Total current assets
|
|
|
61,800
|
|
|
|
52,301
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, net of accumulated
depreciation, depletion and amortization; June 30, 2017, $1,140,993; December 31, 2016, $1,051,600
|
|
|
1,422,425
|
|
|
|
1,497,211
|
|
Other property, net of accumulated depreciation and
amortization; June 30, 2017, $1,024; December 31, 2016, $1,002
|
|
|
984
|
|
|
|
996
|
|
Restricted cash
|
|
|
-
|
|
|
|
52,076
|
|
Other assets
|
|
|
4,134
|
|
|
|
4,186
|
|
Total assets
|
|
$
|
1,489,343
|
|
|
$
|
1,606,770
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND OWNERS’ EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities:
|
|
|
|
|
|
|
|
|
Third party
|
|
$
|
39,709
|
|
|
$
|
31,700
|
|
Related party
|
|
|
-
|
|
|
|
5,797
|
|
Derivative liability
|
|
|
754
|
|
|
|
21,679
|
|
Total current liabilities
|
|
|
40,463
|
|
|
|
59,176
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
159,641
|
|
|
|
180,241
|
|
Long–term debt, net
|
|
|
603,245
|
|
|
|
606,948
|
|
Long–term derivative liability
|
|
|
3
|
|
|
|
955
|
|
Other long–term liabilities
|
|
|
1,372
|
|
|
|
1,043
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners’ equity:
|
|
|
|
|
|
|
|
|
Common unitholders – 49,368,869 units and 49,055,214 units issued and
|
|
|
|
|
|
|
|
|
outstanding as of June 30, 2017 and December 31, 2016, respectively
|
|
|
703,846
|
|
|
|
776,158
|
|
General partner interest
|
|
|
(19,227
|
)
|
|
|
(17,751
|
)
|
Total owners’ equity
|
|
|
684,619
|
|
|
|
758,407
|
|
Total liabilities and owners’ equity
|
|
$
|
1,489,343
|
|
|
$
|
1,606,770
|
|
See accompanying notes to unaudited condensed
consolidated financial statements.
EV Energy Partners, L.P.
Condensed Consolidated Statements of
Operations
(In thousands, except per unit data)
(Unaudited)
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids revenues
|
|
$
|
55,404
|
|
|
$
|
42,365
|
|
|
$
|
111,723
|
|
|
$
|
80,104
|
|
Transportation and marketing–related revenues
|
|
|
648
|
|
|
|
466
|
|
|
|
1,316
|
|
|
|
977
|
|
Total revenues
|
|
|
56,052
|
|
|
|
42,831
|
|
|
|
113,039
|
|
|
|
81,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
26,235
|
|
|
|
26,046
|
|
|
|
50,174
|
|
|
|
54,961
|
|
Cost of purchased natural gas
|
|
|
460
|
|
|
|
305
|
|
|
|
940
|
|
|
|
641
|
|
Dry hole and exploration costs
|
|
|
75
|
|
|
|
771
|
|
|
|
55
|
|
|
|
901
|
|
Production taxes
|
|
|
2,496
|
|
|
|
1,704
|
|
|
|
5,255
|
|
|
|
3,375
|
|
Accretion expense on obligations
|
|
|
1,870
|
|
|
|
2,049
|
|
|
|
3,869
|
|
|
|
4,089
|
|
Depreciation, depletion and amortization
|
|
|
21,531
|
|
|
|
31,648
|
|
|
|
48,511
|
|
|
|
59,853
|
|
General and administrative expenses
|
|
|
7,023
|
|
|
|
7,970
|
|
|
|
13,719
|
|
|
|
16,348
|
|
Impairment of oil and natural gas properties
|
|
|
18,397
|
|
|
|
1,997
|
|
|
|
67,984
|
|
|
|
2,684
|
|
Gain on settlement of contract
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3,185
|
)
|
Gain on sales of oil and natural gas properties
|
|
|
(9
|
)
|
|
|
-
|
|
|
|
(35
|
)
|
|
|
-
|
|
Total operating costs and expenses
|
|
|
78,078
|
|
|
|
72,490
|
|
|
|
190,472
|
|
|
|
139,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(22,026
|
)
|
|
|
(29,659
|
)
|
|
|
(77,433
|
)
|
|
|
(58,586
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net
|
|
|
6,511
|
|
|
|
(35,585
|
)
|
|
|
20,740
|
|
|
|
(25,751
|
)
|
Interest expense
|
|
|
(10,435
|
)
|
|
|
(11,844
|
)
|
|
|
(20,409
|
)
|
|
|
(22,665
|
)
|
Gain on early extinguishment of debt
|
|
|
-
|
|
|
|
47,695
|
|
|
|
-
|
|
|
|
47,695
|
|
Other income, net
|
|
|
723
|
|
|
|
209
|
|
|
|
1,081
|
|
|
|
964
|
|
Total other income (expense), net
|
|
|
(3,201
|
)
|
|
|
475
|
|
|
|
1,412
|
|
|
|
243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(25,227
|
)
|
|
|
(29,184
|
)
|
|
|
(76,021
|
)
|
|
|
(58,343
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
|
|
|
66
|
|
|
|
191
|
|
|
|
29
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(25,161
|
)
|
|
$
|
(28,993
|
)
|
|
$
|
(75,992
|
)
|
|
$
|
(57,993
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(0.50
|
)
|
|
$
|
(0.58
|
)
|
|
$
|
(1.51
|
)
|
|
$
|
(1.16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(basic and diluted)
|
|
|
49,369
|
|
|
|
49,055
|
|
|
|
49,345
|
|
|
|
49,041
|
|
See accompanying notes to unaudited condensed
consolidated financial statements.
EV Energy Partners, L.P.
Condensed Consolidated Statements of
Changes in Owners’ Equity
(In thousands)
(Unaudited)
|
|
Common
Unitholders
|
|
|
General Partner
Interest
|
|
|
Total Owners'
Equity
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2016
|
|
$
|
776,158
|
|
|
$
|
(17,751
|
)
|
|
$
|
758,407
|
|
Equity–based compensation
|
|
|
2,160
|
|
|
|
44
|
|
|
|
2,204
|
|
Net loss
|
|
|
(74,472
|
)
|
|
|
(1,520
|
)
|
|
|
(75,992
|
)
|
Balance, June 30, 2017
|
|
$
|
703,846
|
|
|
$
|
(19,227
|
)
|
|
$
|
684,619
|
|
See accompanying notes to unaudited condensed
consolidated financial statements.
EV Energy Partners, L.P.
Condensed Consolidated Statements of
Cash Flows
(In thousands)
(Unaudited)
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(75,992
|
)
|
|
$
|
(57,993
|
)
|
Adjustments to reconcile net loss to net cash flows provided by operating
activities:
|
|
|
|
|
|
|
|
|
Amortization of volumetric production payment liability
|
|
|
-
|
|
|
|
(2,043
|
)
|
Accretion expense on obligations
|
|
|
3,869
|
|
|
|
4,089
|
|
Depreciation, depletion and amortization
|
|
|
48,511
|
|
|
|
59,853
|
|
Equity–based compensation cost
|
|
|
2,204
|
|
|
|
2,964
|
|
Impairment of oil and natural gas properties
|
|
|
67,984
|
|
|
|
2,684
|
|
Gain on sales of oil and natural gas properties
|
|
|
(35
|
)
|
|
|
-
|
|
(Gain) loss on derivatives, net
|
|
|
(20,740
|
)
|
|
|
25,751
|
|
Cash settlements of matured derivative contracts
|
|
|
(2,929
|
)
|
|
|
36,506
|
|
Gain on early extinguishment of debt
|
|
|
-
|
|
|
|
(47,695
|
)
|
Other
|
|
|
523
|
|
|
|
1,760
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(7,859
|
)
|
|
|
(1,835
|
)
|
Other current assets
|
|
|
847
|
|
|
|
(259
|
)
|
Accounts payable and accrued liabilities
|
|
|
(5,967
|
)
|
|
|
2,510
|
|
Income taxes
|
|
|
-
|
|
|
|
(11,657
|
)
|
Other, net
|
|
|
(217
|
)
|
|
|
(201
|
)
|
Net cash flows provided by operating activities
|
|
|
10,199
|
|
|
|
14,434
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Acquisition of oil and natural gas properties
|
|
|
(58,651
|
)
|
|
|
-
|
|
Additions to oil and natural gas properties
|
|
|
(3,635
|
)
|
|
|
(12,988
|
)
|
Proceeds from sale of oil and natural gas properties
|
|
|
1,989
|
|
|
|
2,420
|
|
Cash settlements from acquired derivative contracts
|
|
|
-
|
|
|
|
2,499
|
|
Restricted cash
|
|
|
52,076
|
|
|
|
-
|
|
Other
|
|
|
17
|
|
|
|
33
|
|
Net cash flows used in investing activities
|
|
|
(8,204
|
)
|
|
|
(8,036
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Repayment of long-term debt borrowings
|
|
|
(21,000
|
)
|
|
|
(33,000
|
)
|
Long–term debt borrowings
|
|
|
17,000
|
|
|
|
48,000
|
|
Redemption of Senior Notes due 2019
|
|
|
-
|
|
|
|
(34,978
|
)
|
Loan costs incurred
|
|
|
-
|
|
|
|
(121
|
)
|
Distributions paid
|
|
|
-
|
|
|
|
(3,868
|
)
|
Net cash flows used in financing activities
|
|
|
(4,000
|
)
|
|
|
(23,967
|
)
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents
|
|
|
(2,005
|
)
|
|
|
(17,569
|
)
|
Cash and cash equivalents – beginning of year
|
|
|
5,557
|
|
|
|
20,415
|
|
Cash and cash equivalents – end of period
|
|
$
|
3,552
|
|
|
$
|
2,846
|
|
See accompanying notes to unaudited condensed
consolidated financial statements.
EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated
Financial Statements
NOTE 1. ORGANIZATION AND NATURE OF
BUSINESS
Nature of
Operations
EV
Energy Partners, L.P. together with its wholly owned subsidiaries (“we,” “our” or “us”) is
a publicly held limited partnership. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited
partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited
liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership.
EnerVest and its affiliates also have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn,
owns a 2% general partner interest in us and all of our incentive distribution rights.
Basis of Presentation
Our unaudited condensed
consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and
Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in annual financial
statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed
or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The
unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary
for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative
of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction
with our audited consolidated financial statements and the related notes included in our Annual Report on Form 10–K for
the year ended December 31, 2016.
All intercompany accounts
and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements,
all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.
Liquidity
Our
unaudited condensed consolidated financial statements for the three and six months ended June 30, 2017 have been prepared assuming
that we will continue as a going concern. As discussed in Note 7, at the end of first quarter of 2018, the leverage covenant in
our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward
commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess
of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance
with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default
and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement
were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes,
in which case the lenders under the indenture could accelerate repayment of the Senior Notes, and we would not have sufficient
liquidity to repay amounts due under the credit agreement and Senior Notes.
Management
is pursuing options to maintain sufficient liquidity and to address the credit agreement covenant compliance issue. Among the
options are (i) working with our bank syndicate to amend our credit agreement, (ii) seeking additional sources of capital, (iii)
divesting or acquiring assets (see Note 3), (iv) redeeming or retiring additional amounts of Senior Notes, and (v) reducing operating
costs. However, there can be no assurance that these options can be implemented and, if implemented, will be successful. Absent
the implementation of actions that bring us into compliance with the covenants of our credit agreement or a meaningful increase
in commodity prices, this raises substantial doubt about our ability to continue as a going concern within one year from the date
these unaudited condensed consolidated financial statements are issued. These financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
New Accounting Standards
In May 2014, the Financial
Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09,
Revenue
from Contracts with Customers
(“ASU 2014-09”
.
This ASU, as amended, superseded virtually all of the revenue
recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step
model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects
the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the
standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09
are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods.
We plan to implement ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if
any, of initial adoption to be recognized at the date of initial application. We are currently in the process of evaluating the
impact of the new standard on our accounting policies, processes, system requirements and financial reporting. Based on the evaluation
performed to date, we expect to identify similar performance obligations as compared with deliverables and separate units of account
previously identified, and we do not expect any change related to the allocation of the transaction price and the timing of our
revenue to have a material impact on our unaudited consolidated financial statements. We will continue to assess the impact of
adopting this ASU.
In March 2016, the
FASB issued ASU No. 2016–09,
Compensation – Stock Compensation
(“ASU 2016-09”). This ASU simplifies
several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes,
forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. We adopted ASU 2016–09
on January 1, 2017. The adoption of this ASU did not have a material impact on our unaudited condensed consolidated financial
statements. See Note 2 for further information.
In January 2017, the
FASB issued ASU No. 2017-01,
Business Combinations (Topic 805): Clarifying the Definition of a Business
(“ASU 2017-01”).
The main objective of ASU 2017-01 is to clarify the definition of a business with the objective of adding guidance to assist entities
with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments
of this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the
fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar
identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated.
If the screen is not met, the amendments of this ASU (i) require that to be considered a business, a set must include, at a minimum,
an input and a substantive process that together significantly contribute to the ability to create output and (ii) remove the
evaluation of whether a market participant could replace missing elements. For public entities, ASU 2017-01 is effective for financial
statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.
No other new accounting
pronouncements issued or effective during the six months ended June 30, 2017 have had or are expected to have a material impact
on our unaudited condensed consolidated financial statements other than those disclosed in our Annual Report on Form 10-K for
the year ended December 31, 2016.
Subsequent Events
We
evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited condensed consolidated
financial statements were issued.
NOTE 2. EQUITY–BASED COMPENSATION
We may grant various
forms of equity–based awards to employees, consultants and directors of EV Management and its affiliates who perform services
for us. These equity–based awards currently consist of phantom units.
We estimated the fair
value of the phantom units using the Black–Scholes option pricing model. These phantom units are subject to graded vesting
over a four year period. Historically, compensation cost has been recognized for these phantom units on a straight–line
basis over the service period, net of estimated forfeitures. As of January 1, 2017, we made an accounting policy election to account
for forfeitures as they occur, and compensation cost is now recognized for these phantom units on a straight-line basis over the
service period with no adjustment for estimated forfeitures. As a result of this election, we recognized a cumulative adjustment
to beginning retained earnings of $1.0 million during the six months ended June 30, 2017. Because the phantom units are equity
awards, this cumulative adjustment was fully offset within owners’ equity.
We recognized compensation
cost related to these phantom units of $1.0 million and $1.4 million in the three months ended June 30, 2017 and 2016, respectively,
and $2.2 million and $3.0 million in the six months ended June 30, 2017 and 2016, respectively. These costs are included in “General
and administrative expenses” in our unaudited condensed consolidated statements of operations.
As of June 30, 2017,
there was $6.5 million of total unrecognized compensation cost related to unvested phantom units which is expected to be
recognized over a weighted average period of 2.1 years.
NOTE 3. ACQUISITIONS AND DIVESTITURES
On January 31, 2017, we acquired a 5.8% working interest in oil and gas properties in Karnes County, Texas for $58.7 million (net of post-closing purchase price adjustments) with $52.1 million of proceeds from the divestiture of our Barnett Shale natural gas properties in December 2016 and $6.6 million of borrowings under our credit facility (the "Eagle Ford Acquisition"). Certain EnerVest institutional partnerships own an 87% working interest in, and a wholly owned subsidiary of EnerVest and its affiliates acts as operator of, the properties. The purchase price of $58.7 million was primarily allocated to proved oil and natural gas properties, and this acquisition has an immaterial impact to our financial statements. The purchase price allocations for this acquisition are preliminary.
In February 2017,
we, along with certain institutional partnerships managed by EnerVest, entered into an Agreement of Sale and Purchase to sell
certain oil and gas properties in Ohio and Pennsylvania to a third party. The transaction closed on April 10, 2017, and we received
net proceeds of $1.1 million. We did not record a gain or loss on this sale.
In April 2017, we
sold certain oil and gas properties in East Texas to a third party. The transaction closed on April 5, 2017, and we received net
proceeds of $0.6 million. We did not record a gain or loss on this sale.
NOTE 4. RISK MANAGEMENT
Our business activities
expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, our floating
rate credit facility exposes us to risks associated with changes in interest rates. As such, future earnings are subject to fluctuation
due to changes in the market prices of oil, natural gas and natural gas liquids and interest rates. We use derivatives to reduce
our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates. Our policies do not permit
the use of derivatives for speculative purposes.
We have elected not
to designate any of our derivatives as hedging instruments
.
Accordingly, changes in the fair value of our derivatives are
recorded immediately to operations as “Gain (loss) on derivatives, net” in our unaudited condensed consolidated statements
of operations.
As of June 30, 2017,
we had entered into commodity contracts with the following terms:
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
Average
|
|
|
|
Hedged
|
|
|
Fixed
|
|
|
Floor
|
|
|
Ceiling
|
|
Period Covered
|
|
Volume
|
|
|
Price
|
|
|
Price
|
|
|
Price
|
|
Oil (MBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps – July 2017 to December 2017
|
|
|
184.0
|
|
|
$
|
52.85
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MmmBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps – July 2017 to December 2017
|
|
|
16,560.0
|
|
|
|
3.07
|
|
|
|
-
|
|
|
|
-
|
|
Swaps – January 2018 to March 2018
|
|
|
4,500.0
|
|
|
|
3.46
|
|
|
|
-
|
|
|
|
-
|
|
Collars – July 2017 to December 2017
|
|
|
5,520.0
|
|
|
|
-
|
|
|
|
2.75
|
|
|
|
3.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids (MBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps – July 2017 to December 2017
|
|
|
386.4
|
|
|
|
16.14
|
|
|
|
-
|
|
|
|
-
|
|
As of June 30,
2017, we had entered into interest rate swaps with the following terms:
Period Covered
|
|
Notional Amount
|
|
|
Floating Rate
|
|
Fixed Rate
|
|
July 2017 – December 2017
|
|
$
|
100,000
|
|
|
1 Month LIBOR
|
|
|
1.039
|
%
|
January 2018 – September 2020
|
|
|
100,000
|
|
|
1 Month LIBOR
|
|
|
1.795
|
%
|
The following table
sets forth the fair values and classification of our outstanding derivatives:
|
|
|
|
|
|
|
|
Net Amounts
|
|
|
|
|
|
|
Gross Amounts
|
|
|
of Assets
|
|
|
|
|
|
|
Offset in the
|
|
|
Presented in the
|
|
|
|
Gross
|
|
|
Unaudited
|
|
|
Unaudited
|
|
|
|
Amounts of
|
|
|
Condensed
|
|
|
Condensed
|
|
|
|
Recognized
|
|
|
Consolidated
|
|
|
Consolidated
|
|
|
|
Assets
|
|
|
Balance Sheet
|
|
|
Balance Sheet
|
|
Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative asset
|
|
$
|
3,535
|
|
|
$
|
(1,542
|
)
|
|
$
|
1,993
|
|
Long–term derivative asset
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
$
|
3,535
|
|
|
$
|
(1,542
|
)
|
|
$
|
1,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative asset
|
|
$
|
201
|
|
|
$
|
-
|
|
|
$
|
201
|
|
Long–term derivative asset
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
$
|
201
|
|
|
$
|
-
|
|
|
$
|
201
|
|
|
|
|
|
|
|
|
|
Net Amounts
|
|
|
|
|
|
|
Gross Amounts
|
|
|
of Liabilities
|
|
|
|
|
|
|
Offset in the
|
|
|
Presented in the
|
|
|
|
Gross
|
|
|
Unaudited
|
|
|
Unaudited
|
|
|
|
Amounts of
|
|
|
Condensed
|
|
|
Condensed
|
|
|
|
Recognized
|
|
|
Consolidated
|
|
|
Consolidated
|
|
|
|
Liabilities
|
|
|
Balance Sheet
|
|
|
Balance Sheet
|
|
Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liability
|
|
$
|
2,296
|
|
|
$
|
(1,542
|
)
|
|
$
|
754
|
|
Long–term derivative liability
|
|
|
3
|
|
|
|
-
|
|
|
|
3
|
|
Total
|
|
$
|
2,299
|
|
|
$
|
(1,542
|
)
|
|
$
|
757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liability
|
|
$
|
21,679
|
|
|
$
|
-
|
|
|
$
|
21,679
|
|
Long–term derivative liability
|
|
|
955
|
|
|
|
-
|
|
|
|
955
|
|
Total
|
|
$
|
22,634
|
|
|
$
|
-
|
|
|
$
|
22,634
|
|
We have entered into
master netting arrangements with our counterparties. The amounts above are presented on a net basis in our unaudited condensed
consolidated balance sheets when such amounts are with the same counterparty. In addition, we have recorded accounts payable and
receivable balances related to our settled derivatives that are subject to our master netting agreements. These amounts are not
included in the above table; however, under our master netting agreements, we have the right to offset these positions against
our forward exposure related to outstanding derivatives.
Should our credit
facility become due and payable because of an event of default, our derivatives that are in a net liability position could also
become due and payable. We could also be required to post cash collateral related to these derivatives under certain circumstances.
As of June 30, 2017 and December 31, 2016, we were not required to post any collateral nor did we hold any collateral associated
with our derivatives.
NOTE 5. FAIR VALUE MEASUREMENTS
The fair value hierarchy
has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined
based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based
on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability,
either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions
used to measure assets and liabilities at fair value.
Recurring Basis
The following table
presents the fair value hierarchy for our assets and liabilities that are required to be measured at fair value on a recurring
basis:
|
|
|
|
|
Fair Value Measurements
at the End of the Reporting Period
|
|
|
|
|
|
|
Quoted
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
|
Fair Value
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
As of June 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids derivatives
|
|
$
|
1,880
|
|
|
$
|
-
|
|
|
$
|
1,880
|
|
|
$
|
-
|
|
Interest rate swaps
|
|
|
113
|
|
|
|
-
|
|
|
|
113
|
|
|
|
-
|
|
|
|
$
|
1,993
|
|
|
$
|
-
|
|
|
$
|
1,993
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids derivatives
|
|
$
|
585
|
|
|
$
|
-
|
|
|
$
|
585
|
|
|
$
|
-
|
|
Interest rate swaps
|
|
|
172
|
|
|
|
-
|
|
|
|
172
|
|
|
|
-
|
|
|
|
$
|
757
|
|
|
$
|
-
|
|
|
$
|
757
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids derivatives
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Interest rate swaps
|
|
|
201
|
|
|
|
-
|
|
|
|
201
|
|
|
|
-
|
|
|
|
$
|
201
|
|
|
$
|
-
|
|
|
$
|
201
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids derivatives
|
|
$
|
22,588
|
|
|
$
|
-
|
|
|
$
|
22,588
|
|
|
$
|
-
|
|
Interest rate swaps
|
|
|
46
|
|
|
|
-
|
|
|
|
46
|
|
|
|
-
|
|
|
|
$
|
22,634
|
|
|
$
|
-
|
|
|
$
|
22,634
|
|
|
$
|
-
|
|
Our derivatives consist
of over–the–counter contracts which are not traded on a public exchange. As the fair value of these derivatives
is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their
basis readily observable market parameters that are actively quoted and can be validated through external sources, including third
party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives
using the income approach with inputs such as the forward curve for commodity prices based on quoted market prices and prospective
volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap
data, such as forward LIBOR curves. Our estimates of fair value have been determined at discrete points in time based on relevant
market data. Furthermore, fair values are adjusted to reflect the credit risk inherent in the transaction, which may include amounts
to reflect counterparty credit quality and/or the effect of our own creditworthiness. Theses assumed credit risk adjustments are
based on published credit ratings, public bond yield spreads and credit default swap spreads. There were no changes in valuation
techniques or related inputs in the six months ended June 30, 2017.
Nonrecurring Basis
During
the three months ended June 30, 2017, we recognized $18.2 million of impairment expense related to proved oil and natural gas
properties; $15.3 million of this impairment related to properties located in the Monroe Field, and $2.9 million related to properties
in East Texas which were sold during April 2017. During the six months ended June 30, 2017, we recognized $67.7 million of impairment
expense related to proved oil and natural gas properties; $49.5 million of this impairment related to properties located in the
Mid-Continent area and the Permian Basin, $15.3 million related to properties located in the Monroe Field, and $2.9 million related
to properties in East Texas which were sold during April 2017. During the three and six months ended June 30, 2016, we did not
incur any impairment charges for any of our proved oil and natural gas properties.
The
fair values were determined using the income approach and were based on the expected present value of the future net cash flows
from reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment
analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated
reserves, appropriate risk–adjusted discount rates and other relevant data.
Financial Instruments
The
estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information.
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities,
derivatives and long–term debt. The carrying amounts of our financial instruments other than long–term debt approximate
fair value because of the short–term nature of the items. Derivatives are recorded at fair value (see above).
The carrying value
of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate
resets frequently and approximates current market rates available to us. The estimated fair value of our senior notes due April
2019 was $186.7 million and $242.6 million at June 30, 2017 and December 31, 2016, respectively, which differs from the carrying
value of $342.2 million and $341.9 million at June 30, 2017 and December 31, 2016, respectively. The fair value of the senior
notes due April 2019 was determined using Level 2 inputs.
NOTE 6. ASSET RETIREMENT OBLIGATIONS
We record an asset
retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period
in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle
facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an
assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. The changes
in the aggregate ARO are as follows:
|
|
2017
|
|
|
2016
|
|
Balance as of January 1
|
|
$
|
183,476
|
|
|
$
|
176,933
|
|
Liabilities incurred
|
|
|
163
|
|
|
|
362
|
|
Revisions
|
|
|
-
|
|
|
|
82
|
|
Accretion expense
|
|
|
3,869
|
|
|
|
3,999
|
|
Settlements and divestitures
|
|
|
(25,185
|
)
|
|
|
(2,235
|
)
|
Liabilities held for sale
|
|
|
(331
|
)
|
|
|
-
|
|
Balance as of June 30
|
|
$
|
161,992
|
|
|
$
|
179,141
|
|
As of June 30, 2017
and December 31, 2016, $2.4 million and $3.2 million of our ARO is classified as current and is included in “Accounts payable
and accrued liabilities” in our unaudited condensed consolidated balance sheets.
NOTE 7. LONG–TERM DEBT
Long–term debt,
net consisted of the following:
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Credit facility
|
|
$
|
261,000
|
|
|
$
|
265,000
|
|
8.0% senior notes due April 2019:
|
|
|
|
|
|
|
|
|
Principal outstanding
|
|
|
343,348
|
|
|
|
343,348
|
|
Unamortized discount and debt issuance costs
(1)
|
|
|
(2,333
|
)
|
|
|
(2,946
|
)
|
Unaccreted premium
(2)
|
|
|
1,230
|
|
|
|
1,546
|
|
|
|
|
342,245
|
|
|
|
341,948
|
|
Total
|
|
$
|
603,245
|
|
|
$
|
606,948
|
|
|
(1)
|
Imputed interest rate of 8.55% and 8.99% for June 30,
2017 and December 31, 2016, respectively.
|
|
(2)
|
Imputed interest rate of 7.50% and 7.22% for June 30,
2017 and December 31, 2016, respectively.
|
Credit Facility
As of June 30, 2017,
we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility are secured by a first priority
lien on substantially all of our oil and natural gas properties. We may use borrowings under the facility for acquiring and developing
oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to
partners. We also may use up to $100.0 million of available borrowing capacity for letters of credit. As of June 30, 2017, we
have a $0.3 million letter of credit outstanding.
The facility does
not require any repayments of amounts outstanding until it expires in February 2020. Borrowings under the facility bear interest
at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums
based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 4.22% and 3.75%
at June 30, 2017 and December 31, 2016, respectively).
Borrowings under the
facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural
gas reserves. In April 2017, the borrowing base under the facility was decreased $75.0 million to $375.0 million. As of June 30,
2017, the borrowing base under the facility was $375.0 million. The borrowing base is subject to scheduled redeterminations as
of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request
of the lenders and with one calculation that may be made at our request during each calendar year in connection with material
acquisitions or divestitures of properties.
The facility
requires the maintenance of the following (as defined in the facility):
|
·
|
the
senior secured funded debt to earnings plus interest expense, taxes, depreciation, depletion
and amortization expense and exploration expense (“EBITDAX”) ratio covenant
to be no greater than (a) for the fiscal quarters ending March 31, 2017 and June 30,
2017, 3.5 to 1.0 and (b) for the fiscal quarter ending September 30, 2017 and December
31, 2017, 4.0 to 1.0;
|
|
·
|
the
total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal
quarter ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30,
2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December
31, 2018 and thereafter, 4.25 to 1.0;
|
|
·
|
the
EBITDAX to cash interest expense ratio covenant to be no less than (a) for the fiscal
quarters ending March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (b) for the fiscal quarters
ending September 30, 2017 and thereafter, 1.5 to 1.0; and
|
|
·
|
limits
cash held by us to the greater of 5% of the current borrowing base or $30.0 million.
|
As of June 30, 2017,
we were in compliance with these financial covenants. Should prices decline significantly from current levels, the borrowing base
could be reduced again in future redeterminations, which would impact our short–term liquidity. At the end of first quarter
of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to
EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely
have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement,
and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance
with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit
agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in
default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment
of the Senior Notes.
8.0% Senior Notes due April 2019
Our senior notes due
April 2019 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing
wholly owned subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes.
Neither EV Energy Partners, L.P. nor Finance have independent assets or operations apart from the assets and operations of our
subsidiaries.
NOTE 8. COMMITMENTS AND CONTINGENCIES
We are involved in
disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal
actions will have a material effect on our unaudited condensed consolidated financial statements and no amounts have been accrued
at June 30, 2017 or December 31, 2016.
NOTE 9. OWNERS’ EQUITY
Units
Outstanding
At June 30, 2017,
owners’ equity consists of 49,368,869 common units, representing a 98% limited partnership interest in us, and a 2% general
partnership interest.
Issuance
of Units
In the six months
ended June 30, 2017, we issued 0.3 million common units related to the vesting of equity–based awards.
Cash Distributions
During 2016, the board
of directors of EV Management announced that it had elected to suspend distributions to unitholders for all four quarters of 2016.
The board of directors also elected to suspend distributions for the first and second quarters of 2017.
NOTE 10. EARNINGS PER LIMITED PARTNER
UNIT
The following sets
forth the calculation of earnings per limited partner unit:
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Net loss
|
|
$
|
(25,161
|
)
|
|
$
|
(28,993
|
)
|
|
$
|
(75,992
|
)
|
|
$
|
(57,993
|
)
|
General partner’s 2% interest in net loss
|
|
|
503
|
|
|
|
580
|
|
|
|
1,520
|
|
|
|
1,160
|
|
Earnings attributable to unvested phantom units
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Limited partners’ interest in net loss
|
|
$
|
(24,658
|
)
|
|
$
|
(28,413
|
)
|
|
$
|
(74,472
|
)
|
|
$
|
(56,833
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per limited partner unit (basic and diluted)
|
|
$
|
(0.50
|
)
|
|
$
|
(0.58
|
)
|
|
$
|
(1.51
|
)
|
|
$
|
(1.16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding (basic and diluted)
|
|
|
49,369
|
|
|
|
49,055
|
|
|
|
49,345
|
|
|
|
49,041
|
|
NOTE 11. RELATED PARTY TRANSACTIONS
Pursuant
to an omnibus agreement, we paid EnerVest $3.5 million and $4.0 million in the three months ended June 30, 2017 and 2016, respectively,
and $7.0 million and $8.0 million in the six months ended June 30, 2017 and 2016, respectively, in monthly administrative fees
for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us
based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable
and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general
and administrative expenses in our unaudited condensed consolidated statements of operations.
We have entered into operating agreements whereby a wholly owned subsidiary of EnerVest and its affiliates acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest approximately $4.9 million and $4.6 million in the three months ended June 30, 2017 and 2016, respectively, and $9.4 million and $10.8 million in the six months ended June 30, 2017 and 2016, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis. These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.
As
of June 30, 2017, EnerVest Operating owed us $7.2 million and partnerships managed by EnerVest owed us nothing. As of December
31, 2016, we owed EnerVest Operating $5.8 million and partnerships managed by EnerVest owed us $0.7 million.
NOTE 12. OTHER SUPPLEMENTAL INFORMATION
Supplemental cash
flows and noncash transactions were as follows:
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
Supplemental cash flows information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
19,220
|
|
|
$
|
20,984
|
|
Cash paid for income taxes, net of refunds
|
|
|
-
|
|
|
|
11,657
|
|
|
|
As of June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
Costs for additions to oil and natural gas properties
|
|
|
|
|
|
|
|
|
in accounts payable and accrued liabilities
|
|
$
|
6,959
|
|
|
$
|
2,497
|
|
Accounts payable and accrued liabilities
consisted of the following:
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Lease operating expenses
|
|
$
|
13,462
|
|
|
$
|
9,835
|
|
Costs for additions to oil and natural gas properties
|
|
|
6,959
|
|
|
|
668
|
|
Production and ad valorem taxes
|
|
|
5,925
|
|
|
|
7,382
|
|
Interest
|
|
|
5,879
|
|
|
|
6,029
|
|
Current portion of ARO
|
|
|
2,350
|
|
|
|
3,235
|
|
General and administrative expenses
|
|
|
1,961
|
|
|
|
3,095
|
|
Derivative settlements
|
|
|
-
|
|
|
|
106
|
|
Other
|
|
|
3,173
|
|
|
|
1,350
|
|
Total
|
|
$
|
39,709
|
|
|
$
|
31,700
|
|
ITEM 2. MANAGEMENT’S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s
Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed
consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year
ended December 31, 2016.
OVERVIEW
We are a Delaware
limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general
partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware
limited liability company.
We operate in one
reportable segment engaged in the acquisition, development and production of oil and natural gas properties and all of our operations
are located in the United States.
As of June 30, 2017,
our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes
the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), South Texas, the Monroe Field in Northern Louisiana,
the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin. As of December 31, 2016, we had
estimated net proved reserves of 12.6 MMBbls of oil, 575.3 Bcf of natural gas and 33.4 MMBbls of natural gas liquids, or 851.2
Bcfe, and a standardized measure of $371.1 million.
Current Price Environment
Oil, natural gas and
natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been
volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously,
and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and
the first half of 2017, they have continued to fluctuate.
Factors contributing
to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle
East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization
of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing
to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher
levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate
to the price of oil and, accordingly, prices remain lower than historical levels and are likely to continue to directionally follow
the market for oil.
In the six months
ended June 30, 2017, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices
for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further
declines in prices could also have a significant adverse impact on the value and quantities of our reserves, assuming no other
changes in our development plans.
As specified by the
SEC, the prices for oil, natural gas and natural gas liquids used to calculate our reserves were the average prices during the
year determined using the price on the first day of each month. The prices utilized in calculating our total estimated proved
reserves at December 31, 2016 were $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, which was significantly lower
than forward strip prices. Had we used the forward strip prices at December 31, 2016 through December 31, 2029, we estimate that
the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately
111% higher and that our reserves on an Mcfe basis would have been approximately 50% higher than our reserves calculated using
SEC prices.
Our Response to the Current Price Environment
Given current forward
oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous
years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility.
These steps include:
|
·
|
focusing
on managing and enhancing our base business through continuing effort to reduce operating
and capital costs;
|
|
·
|
increasing
our capital spending budget to $30 - $45 million from $10.7 million in 2016, in an effort
to maintain current production levels;
|
|
·
|
maintaining
a sufficient liquidity position to manage through the current environment, which includes
continuing to assess the appropriate distribution levels every quarter;
|
|
·
|
continuing
to evaluate strategic acquisitions of long-life, producing oil and natural gas properties
such as our Eagle Ford Acquisition in January 2017; and
|
|
·
|
further
realizing the value of our undeveloped acreage through either alternative sources of
capital, including farmouts, production payments and joint ventures, or potential monetization
of acreage.
|
During 2016, the board
of directors of EV Management elected to suspend distributions to unitholders for all four quarters of 2016. The board of directors
also elected to suspend distributions for the first and second quarters of 2017. The company continues to generate positive distributable
cash flow, albeit at significantly lower levels than in previous years. The board of directors will continue to evaluate on a
quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows
have increased to a level that can support a sustainable distribution.
As of August 7, 2017,
we have $254.0 million outstanding under our credit facility and $343.3 million of our senior notes due 2019 outstanding, for
a total of $597.3 million, and we have over $120 million of liquidity between our borrowing base capacity and cash on hand. Please
see Note 1 to our unaudited condensed consolidated financial statements included in “Item 1. Condensed Consolidated Financial
Statements (unaudited)” contained herein for additional information regarding our liquidity.
Business Environment
One
of our primary business objectives is to generate sufficient excess cash flow that will allow us to reinstate a stable distribution,
which we will grow over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated
from our operations, which will fluctuate from quarter to quarter based on, among other things:
|
·
|
the
prices at which we will sell our oil, natural gas liquids and natural gas production;
|
|
·
|
our
ability to hedge commodity prices;
|
|
·
|
the
amount of oil, natural gas liquids and natural gas we produce; and
|
|
·
|
the
level of our operating and administrative costs.
|
In order to mitigate
the impact of lower prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future
to reduce the impact of price volatility on our cash flows. Although we have entered into derivative contracts covering a portion
of our future production through March 2018, a sustained lower price environment would result in lower prices for unprotected
volumes and reduce the prices at which we can enter into derivative contracts for additional volumes in the future. We have mitigated,
but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. An extended
period of depressed commodity prices would alter our acquisition and development plans, adversely affect our growth strategy and
our ability to access additional capital in the capital markets and reduce the cash we have available to pay distributions, which
may require us to further delay our ability to reinstate our quarterly distribution.
The primary factors
affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling
program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our
wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth
will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain
our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.
Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including
our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering
lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result,
cash available for distribution.
We focus our efforts
on increasing our reserves and production while controlling costs at a level that is appropriate for long–term operations.
Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.
RESULTS OF OPERATIONS
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
372
|
|
|
|
313
|
|
|
|
707
|
|
|
|
630
|
|
Natural gas liquids (MBbls)
|
|
|
528
|
|
|
|
585
|
|
|
|
1,039
|
|
|
|
1,187
|
|
Natural gas (MMcf)
|
|
|
10,241
|
|
|
|
12,951
|
|
|
|
20,607
|
|
|
|
25,769
|
|
Net production (MMcfe)
|
|
|
15,640
|
|
|
|
18,341
|
|
|
|
31,087
|
|
|
|
36,672
|
|
Average sales price per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
44.06
|
|
|
$
|
41.08
|
|
|
$
|
45.48
|
|
|
$
|
35.06
|
|
Natural gas liquids (Bbl)
|
|
|
18.26
|
|
|
|
15.89
|
|
|
|
19.57
|
|
|
|
14.03
|
|
Natural gas (Mcf)
|
|
|
2.87
|
|
|
|
1.56
|
|
|
|
2.87
|
|
|
|
1.60
|
|
Mcfe
|
|
|
3.54
|
|
|
|
2.31
|
|
|
|
3.59
|
|
|
|
2.18
|
|
Average unit cost per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.68
|
|
|
$
|
1.42
|
|
|
$
|
1.61
|
|
|
$
|
1.50
|
|
Production taxes
|
|
|
0.16
|
|
|
|
0.09
|
|
|
|
0.17
|
|
|
|
0.09
|
|
Total
|
|
|
1.84
|
|
|
|
1.51
|
|
|
|
1.78
|
|
|
|
1.59
|
|
Depreciation, depletion and amortization
|
|
|
1.38
|
|
|
|
1.73
|
|
|
|
1.56
|
|
|
|
1.63
|
|
General and administrative expenses
|
|
|
0.45
|
|
|
|
0.43
|
|
|
|
0.44
|
|
|
|
0.45
|
|
Three Months Ended June 30, 2017 Compared
with the Three Months Ended June 30, 2016
Net loss for the three
months ended June 30, 2017 was $25.2 million compared with $29.0 million for the three months ended June 30, 2016. The significant
factors in this change were a $42.1 million favorable change in gain on derivatives, a $13.2 million increase in total revenues,
a $10.1 million decrease in depreciation, depletion and amortization, partially offset by a $47.7 million decrease as a result
of the gain on extinguishment of debt during 2016 and a $16.4 million increase in impairment of oil and natural gas properties.
Oil, natural gas and
natural gas liquids revenues for the three months ended June 30, 2017 totaled $55.4 million, an increase of $13.0 million compared
with the three months ended June 30, 2016. This was the result of an increase of $19.2 million related to higher prices offset
by a decrease of $6.2 million primarily related to decreased natural gas and natural gas liquids production.
Lease
operating expenses for the three months ended June 30, 2017 increased $0.2 million compared with the three months ended June 30,
2016 as the result of $4.7 million from a higher unit cost per Mcfe, partially offset by $4.5 million from decreased production.
Lease operating expenses were $1.68 per Mcfe in the three months ended June 30, 2017 compared with $1.42 per Mcfe in the three
months ended June 30, 2016.
Depreciation,
depletion and amortization (“DD&A”) for the three months ended June 30, 2017 decreased $10.1 million compared
with the three months ended June 30, 2016 as a result of $6.4 million from a lower unit cost per Mcfe combined with $3.7 million
decreased production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and
impairments. DD&A was $1.38 per Mcfe in the three months ended June 30, 2017 compared with $1.73 per Mcfe in the three months
ended June 30, 2016.
General and administrative
expenses for the three months ended June 30, 2017 totaled $7.0 million, a decrease of $0.9 million compared with the three months
ended June 30, 2016. This decrease is primarily the result of $0.4 million of lower compensation costs and $0.5 million of lower
fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.45 per Mcfe in the three months
ended June 30, 2017 compared with $0.43 per Mcfe in the three months ended June 30, 2016.
In
the three months ended June 30, 2017, we incurred proved property impairment of $15.3 million related to proved oil and natural
gas properties located in the Monroe Field and $2.9 million related to proved oil and natural gas properties located in East Texas
which were sold during April 2017. During the three month ended June 30, 2017, we also incurred leasehold impairment charges of
$0.2 million. In the three months ended June 30, 2016, we incurred leasehold impairment charges of $2.0 million.
Gain on derivatives,
net was $6.5 million for the three months ended June 30, 2017 compared with a loss of $35.6 million for the three months ended
June 30, 2016. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at June
30, 2017 for oil averaged $47.19 per Bbl compared with $51.72 at March 31, 2017, and the 12 month forward prices at June 30, 2017
for natural gas averaged $3.09 per MmBtu compared with $3.37 at March 31, 2017. The 12 month forward price at June 30, 2016 for
oil averaged $49.42 per Bbl compared with $38.56 at March 31, 2016, and the 12 month forward prices at June 30, 2016 for natural
gas averaged $3.02 per MmBtu compared with $2.19 at March 31, 2016.
Interest expense for
the three months ended June 30, 2017 decreased $1.4 million compared with the three months ended June 30, 2016 due to $1.2 million
from less loan cost write off than the prior year combined with $0.4 million from a lower weighted average long–term debt
balance and, partially offset by $0.2 million from a higher weighted average effective interest rate.
Six Months Ended June 30, 2017 Compared
with the Six Months Ended June 30, 2016
Net loss for the six
months ended June 30, 2017 was $76.0 million compared with $58.0 million for the six months ended June 30, 2016. The significant
factors in this change were a $47.7 million decrease as a result of the gain on extinguishment of debt during 2016 and a $65.3
million increase in impairment of oil and natural gas properties, partially offset by a $46.5 million favorable change in gain
on derivatives, a $32.0 million increase in total revenues, and a $11.3 million decrease in depreciation, depletion and amortization.
Oil, natural gas and
natural gas liquids revenues for the six months ended June 30, 2017 totaled $111.7 million, an increase of $31.6 million compared
with the six months ended June 30, 2016. This was the result of an increase of $45.8 million related to higher prices offset by
a decrease of $14.2 million primarily related to decreased natural gas and natural gas liquids production.
Lease
operating expenses for the six months ended June 30, 2017 decreased $4.8 million compared with the six months ended June 30, 2016
as the result of $9.0 million from decreased production, partially offset by $4.2 million from a higher unit cost per Mcfe. Lease
operating expenses were $1.61 per Mcfe in the six months ended June 30, 2017 compared with $1.50 per Mcfe in the six months ended
June 30, 2016.
Depreciation,
depletion and amortization (“DD&A”) for the six months ended June 30, 2017 decreased $11.3 million compared with
the six months ended June 30, 2016 as a result of $8.7 million from decreased production combined with $2.6 million from a lower
unit cost per Mcfe. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and
impairments. DD&A was $1.56 per Mcfe in the six months ended June 30, 2017 compared with $1.63 per Mcfe in the six months
ended June 30, 2016.
General and administrative
expenses for the six months ended June 30, 2017 totaled $13.7 million, a decrease of $2.6 million compared with the six months
ended June 30, 2016. This decrease is primarily the result of $1.1 million of lower compensation costs and $1.0 million of lower
fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.44 per Mcfe in the six months ended
June 30, 2017 compared with $0.45 per Mcfe in the six months ended June 30, 2016.
In
the six months ended June 30, 2017, we incurred proved property impairment of $49.5 million related to proved oil and natural
gas properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to proved oil and natural gas properties
located in the Monroe Field, and $2.9 million related to proved oil and natural gas properties located in East Texas which were
sold in April 2017. During the six months ended June 30, 2017, we also incurred leasehold impairment charges of $0.3 million.
In the six months ended June 30, 2016, we incurred leasehold impairment charges of $2.7 million.
Gain on derivatives,
net was $20.7 million for the six months ended June 30, 2017 compared with a loss of $25.8 million for the six months ended June
30, 2016. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at June 30,
2017 for oil averaged $47.19 per Bbl compared with $56.19 at December 31, 2016, and the 12 month forward prices at June 30, 2017
for natural gas averaged $3.09 per MmBtu compared with $3.61 at December 31, 2016. The 12 month forward price at June 30, 2016
for oil averaged $49.42 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at June 30, 2016 for
natural gas averaged $3.02 per MmBtu compared with $2.49 at December 31, 2015.
Interest expense for
the six months ended June 30, 2017 decreased $2.3 million compared with the six months ended June 30, 2016 due to $1.4 million
from a lower weighted average long–term debt balance combined with $1.2 million from less loan cost write off than the prior
year partially offset by $0.3 million from a higher weighted average effective interest rate.
LIQUIDITY AND CAPITAL RESOURCES
Historically, our
primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility
and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related
assets, development of our oil and natural gas properties, distributions to our unitholders and general partner and working capital
needs.
In response to continued
price volatility, we have taken a number of actions to preserve our liquidity and financial flexibility and, as of August 7, 2017,
we have over $120 million of liquidity between our borrowing base capacity and cash on hand. However, given current forward oil
and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous
years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility.
These steps include those outlined in “—Overview—Our Response to the Current Price Environment.”
For 2017, we believe
that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility
will be adequate to fund our capital budget and satisfy our short–term liquidity needs.
We may also utilize
borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities
through public offerings or private placements, to fund our acquisitions and long–term liquidity needs. Our ability to complete
future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing
market conditions and our financial condition.
Long–term Debt
As of June 30, 2017,
we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility may not exceed a “borrowing
base” determined by the lenders based on our oil and natural gas reserves. As of June 30, 2017, the borrowing base was $375.0
million, and we had $261.0 million outstanding.
In April 2017, the
borrowing base was decreased to $375.0 million. Although the borrowing base under the credit facility was reduced, we believe
we will maintain sufficient liquidity. However, should prices decline significantly from current levels, the borrowing base could
be reduced again in future redeterminations, which would impact our liquidity. At the end of first quarter of 2018, the leverage
covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on
current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX
ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not
be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be
an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under
the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing
the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes, and we would not
have sufficient liquidity to repay amounts due under the credit agreement and Senior Notes.
As of June 30, 2017,
we have $343.3 million in aggregate principal amount outstanding of our 8.0% senior notes due April 2019. As of June 30, 2017,
the aggregate carrying amount of the senior notes due 2019 was $342.2 million.
As of August 7, 2017,
we have $254.0 million outstanding under our credit facility and $343.3 million of our senior notes due April 2019 outstanding,
for a total of $597.3 million.
For additional information
about our long–term debt, such as interest rates and covenants, please see “Item 1. Condensed Consolidated Financial
Statements (unaudited)” contained herein.
Cash and Short–term Investments
At June 30, 2017,
we had $3.6 million of cash and short–term investments, which included $0.7 million of short–term investments. With
regard to our short–term investments, we invest in money market accounts with major financial institutions.
Counterparty Exposure
All of our derivative
contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial
counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of
June 30, 2017, all of our counterparties have performed pursuant to their derivative contracts.
Cash Flows
Cash flows provided
by (used in) type of activity were as follows:
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
Operating activities
|
|
$
|
10,199
|
|
|
$
|
14,434
|
|
Investing activities
|
|
|
(8,204
|
)
|
|
|
(8,036
|
)
|
Financing activities
|
|
|
(4,000
|
)
|
|
|
(23,967
|
)
|
Operating Activities
Cash flows from operating
activities provided $10.2 million and $14.4 million in the six months ended June 30, 2017 and 2016, respectively. The significant
factors in the change were $13.4 million change in working capital, primarily related to higher accounts receivable as a result
of higher sales prices during 2017 and $39.4 million of decreased cash settlements from our matured derivative contracts, partially
offset by $32.0 million of higher revenues during 2017 and an $11.7 million federal tax payment related to the conversion of an
acquired corporation to a single member LLC in 2016.
Investing Activities
During the six months
ended June 30, 2017, we spent $58.7 million for acquisitions of oil and natural gas properties, utilized $52.1 million of restricted
cash for those acquisitions, spent $3.6 million for additions to our oil and natural gas properties and received $2.0 million
in proceeds from the sale of oil and natural gas properties. During the six months ended June 30, 2016, we spent $13.0 million
for additions to our oil and natural gas properties and received $2.5 million in cash settlements from acquired derivative contracts
and $2.4 million in proceeds from the sale of oil and natural gas properties.
Financing Activities
During the six months
ended June 30, 2017, we received $17.0 million from borrowings under our credit facility and repaid $21.0 million of long–term
debt borrowings.
During the six months
ended June 30, 2016, we received $48.0 million from borrowings under our credit facility, repaid $33.0 million of long-term debt
borrowings and paid distributions of $3.9 million to holders of our common units, phantom units and our general partner. We also
redeemed $82.7 million of our senior notes due 2019 for $35.0 million.
FORWARD–LOOKING STATEMENTS
This Form 10–Q
contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Exchange Act (each a “forward–looking statement”). These forward–looking statements
relate to, among other things, the following:
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·
|
our
ability to meet the financial covenants in our debt agreements and continue as a going
concern;
|
|
·
|
our
future financial and operating performance and results, and our ability to resume and
sustain distributions;
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|
·
|
our
business strategy and plans, and future capital expenditures, including plans to optimize
the value of our assets;
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|
·
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our
estimated net proved reserves, PV–10 value and standardized measure;
|
|
·
|
our
future derivative activities; and
|
|
·
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our
plans and forecasts.
|
We have based these
forward–looking statements on our current assumptions, expectations and projections about future events.
The words “anticipate,”
“believe,” “ensure,” “expect,” “if,” “intend,” “estimate,”
“project,” “forecasts,” “predict,” “outlook,” “aim,” “will,”
“could,” “should,” “would,” “may,” “likely” and similar expressions,
and the negative thereof, are intended to identify forward–looking statements. These statements discuss future expectations,
contain projections of results of operations or of financial condition or state other “forward–looking” information.
We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law.
These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially
differ from our expectations in this Form 10–Q including, but not limited to:
|
·
|
fluctuations
in prices of oil, natural gas and natural gas liquids and the length of time commodity
prices remain depressed;
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|
·
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significant
disruptions in the financial markets;
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|
·
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future
capital requirements and availability of financing;
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|
·
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uncertainty
inherent in estimating our reserves;
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|
·
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risks
associated with drilling and operating wells;
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·
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discovery,
acquisition, development and replacement of reserves;
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|
·
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cash
flows and liquidity;
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|
·
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timing
and amount of future production of oil, natural gas and natural gas liquids;
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|
·
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availability
of drilling and production equipment;
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|
·
|
marketing
of oil, natural gas and natural gas liquids;
|
|
·
|
developments
in oil and natural gas producing countries;
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|
·
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general
economic conditions;
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|
·
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governmental
regulations;
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|
·
|
activities
taken or non–performance by third parties, including suppliers, contractors, operators,
transporters and purchasers of our production and counterparties to our derivative financial
instrument contracts;
|
|
·
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hedging
decisions, including whether or not to enter into derivative financial instruments;
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|
·
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actions
of third party co–owners of interest in properties in which we also own an interest;
|
|
·
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fluctuations
in interest rates and the value of the U.S. dollar in international currency markets;
and
|
|
·
|
our
ability to effectively integrate companies and properties that we acquire.
|
All of our forward–looking
information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected.
Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of
any of those risk factors identified in the “Risk Factors” section included in Item 1A of our
Annual Report
on Form 10–K for the year ended December 31, 2016 and in “Item 1A. Risk Factors” contained herein.
Our revenues, operating
results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices
for oil, natural gas and natural gas liquids. Declines in prices may materially adversely affect our financial condition, liquidity,
ability to obtain financing and operating results. Lower prices also may reduce the amount of oil, natural gas or natural gas
liquids that we can produce economically. A decline in prices could have a material adverse effect on the estimated value and
estimated quantities of our reserves, our ability to fund our operations and our financial condition, cash flows, results of operations
and access to capital. Historically, prices and markets have been volatile, with prices fluctuating widely, and they are likely
to continue to be volatile.