Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Because the Linn Acquisition was determined to be a business combination as the acquired oil and natural gas properties met the definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the acquisition date. The following assumptions were used to determine the fair value of the oil and natural gas properties:
|
|
|
|
Discount rate
|
9.50
|
%
|
Reserve risk factor
(1)
|
35%-100%
|
|
Oil price
|
three years NYMEX WTI forward curve
|
|
Natural gas price
|
three years NYMEX Henry Hub forward curve
|
|
NGL price
|
39% of oil price
|
|
Price escalation
(2)
|
2.00
|
%
|
(1)
Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%.
|
(2)
Prices were escalated at the end of the forward curve
|
The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands):
|
|
|
|
|
Consideration given
|
|
Equity units
|
$
|
1,281,743
|
|
Allocation of purchase price
|
|
Inventory
|
$
|
205
|
|
Proved oil and natural gas properties
|
214,647
|
|
Unproved oil and natural gas properties
|
1,086,600
|
|
Total assets acquired
|
1,301,452
|
|
Asset retirement obligations
|
(7,547
|
)
|
Revenue suspense
|
(12,162
|
)
|
Total fair value of net assets acquired
|
$
|
1,281,743
|
|
The following unaudited pro forma combined results of operations is provided for the
three and nine
months ended September 30, 2017 as though the Linn Acquisition had been completed as of the earliest period presented at the time of the acquisition. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition.
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, 2017
|
|
Nine Months Ended
September 30, 2017
|
|
(in thousands)
|
Revenue
|
$
|
55,119
|
|
|
$
|
156,593
|
|
Net income
|
$
|
17,052
|
|
|
$
|
55,253
|
|
Acquisitions of Unproved Properties
During the year ended December 31, 2017, the Company acquired, from unrelated third parties, interests in approximately
23,400
net acres of leasehold in separately negotiated transactions for aggregate cash consideration of
$49.7 million
, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties.
As discussed in
Note 12 –Transactions with Affiliates
, Citizen and Linn acquired acreage during 2017 on behalf of Roan LLC for
$63.0 million
, which was included in accounts payable and accrued liabilities – affiliates at December 31, 2017. In March 2018, Roan LLC paid Linn
$22.9 million
in cash and issued equity units to both Citizen and Linn to settle the amount due.
Note 5 – Oil and Natural Gas Properties
The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following:
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
(in thousands)
|
Oil and natural gas properties
|
|
|
|
Proved
|
$
|
1,276,950
|
|
|
$
|
750,492
|
|
Unproved
|
1,152,942
|
|
|
1,126,459
|
|
Less: accumulated depreciation, depletion, amortization and impairment
|
(183,557
|
)
|
|
(78,307
|
)
|
Oil and natural gas properties, net
|
$
|
2,246,335
|
|
|
$
|
1,798,644
|
|
The Company recorded depletion expense on capitalized oil and natural gas properties of $
36.7 million
and $
10.7 million
for the three months ended
September 30, 2018
and
2017
, respectively, and $
82.4 million
and $
22.0 million
for the
nine
months ended
September 30, 2018
and
2017
, respectively.
For the
three and nine
months ended
September 30, 2018
, the Company recorded amortization expense on its unproved oil and natural gas properties of $
11.2 million
and $
25.6 million
, respectively, which is reflected in exploration expense on the accompanying condensed consolidated statements of operations. There was
no
such expense recorded for the
three and nine
months ended
September 30, 2017
. Unproved leasehold
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
amortization for the
three and nine
months ended
September 30, 2018
reflects consideration of the Company’s drilling plans and the lease terms of its existing unproved properties. For the
three and nine
months ended
September 30, 2017
, the Company recorded impairment expense on its unproved oil and natural gas properties of
$4.2 million
and
$4.5 million
, respectively, for leases which expired.
No
impairment of proved oil and natural gas properties was recorded for the
three and nine
months ended
September 30, 2018
.
Note 6 – Asset Retirement Obligations
The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the
nine
months ended
September 30, 2018
(in thousands):
|
|
|
|
|
Asset retirement obligation, December 31, 2017
|
$
|
10,769
|
|
Liabilities incurred or acquired
|
1,815
|
|
Revisions in estimated cash flows
|
318
|
|
Liabilities settled
|
(111
|
)
|
Accretion expense
|
620
|
|
Asset retirement obligation, September 30, 2018
|
13,411
|
|
Less: current portion of obligations
|
535
|
|
Asset retirement obligation – long term
|
$
|
12,876
|
|
Note 7 – Long-Term Debt
In September 2017, the Company entered into a
$750.0 million
credit agreement with an initial borrowing base of
$200.0 million
and maturity on September 5, 2022 (as amended, the “2017 Credit Facility”). In September 2018, the redetermination resulted in an increase to the borrowing base to
$675.0 million
. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of
September 30, 2018
, the Company had $
394.6 million
of outstanding borrowings and
no
letters of credit outstanding under the 2017 Credit Facility. The 2017 Credit Facility is secured by substantially all of the assets of the Company.
The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to
$500 million
before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (“LIBOR”) and alternate base rate (“ABR”) loans by
0.25%
for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to
0.375%
.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement):
|
|
|
|
|
|
Utilization Level
|
Utilization
|
LIBOR Margin
|
Applicable Margin
|
Commitment Fee
|
Level I
|
<25%
|
2.00%
|
1.00%
|
0.375%
|
Level II
|
>25% but <50%
|
2.25%
|
1.25%
|
0.375%
|
Level III
|
>50% but <75%
|
2.50%
|
1.50%
|
0.500%
|
Level IV
|
>75% but <90%
|
2.75%
|
1.75%
|
0.500%
|
Level V
|
>90%
|
3.00%
|
2.00%
|
0.500%
|
The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a)
80%
of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed
50%
of the borrowing base, the Company is required to hedge a minimum of
50%
of the future production expected to be derived from proved developed reserves for the next
eight
quarters per its most recent reserve report.
The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than
4.00
to
1.00
and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815
Derivatives and Hedging
and ASC Topic 410
Asset Retirement and Environmental Obligations
) as of the fiscal quarter ended of not less than
1.00
to
1.00
.
As of
September 30, 2018
, the Company was in compliance with the covenants under the 2017 Credit Facility.
Prior to the 2017 Credit Facility, Citizen had a
two
-year,
$500.0 million
credit facility (“Citizen 2017 Credit Facility”) with an initial borrowing base of
$82.5 million
. In August 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of
$20.3 million
was repaid.
Note 8 – Derivative Instruments
The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, or Panhandle Eastern Pipeline. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.
The following table reflects the Company’s open commodity contracts at
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2019
|
|
2020
|
|
Total
|
Oil fixed price swaps
|
|
|
|
|
|
|
|
Volume (Bbl)
|
1,233,180
|
|
|
5,540,670
|
|
|
1,599,500
|
|
|
8,373,350
|
|
Weighted-average price
|
$
|
57.09
|
|
|
$
|
59.86
|
|
|
$
|
63.14
|
|
|
$
|
60.08
|
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
8,004,000
|
|
|
29,200,000
|
|
|
12,325,000
|
|
|
49,529,000
|
|
Weighted-average price
|
$
|
2.94
|
|
|
$
|
2.86
|
|
|
$
|
2.63
|
|
|
$
|
2.81
|
|
Natural gas basis swaps
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
4,600,000
|
|
|
21,900,000
|
|
|
3,640,000
|
|
|
30,140,000
|
|
Weighted-average price
|
$
|
0.54
|
|
|
$
|
0.58
|
|
|
$
|
0.62
|
|
|
$
|
0.58
|
|
The Company nets the fair value of derivative instruments by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. See
Note 9 – Fair Value Measurements
for further information regarding the fair value measurement of the Company’s derivatives.
As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in (loss) gain on derivative contracts included in the consolidated statement of operations.
The following table presents the Company’s (loss) gain on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the three and nine months ended
September 30, 2018
and
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(in thousands)
|
(Loss) gain on derivative contracts
|
$
|
(36,704
|
)
|
|
$
|
131
|
|
|
$
|
(100,920
|
)
|
|
$
|
2,385
|
|
Net cash (paid) received upon settlement of derivative contracts
|
$
|
(13,551
|
)
|
|
$
|
2,255
|
|
|
$
|
(27,462
|
)
|
|
$
|
2,385
|
|
Net cash received upon settlement of derivative contracts prior to contractual maturity
|
$
|
—
|
|
|
2,255
|
|
|
$
|
377
|
|
|
$
|
2,255
|
|
Note 9 – Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:
Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.
Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the
three and nine
months ended
September 30, 2018
, the Company did
not
have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company's recurring fair value measurements are performed for its commodity derivatives.
Commodity Derivative Instruments
Commodity derivative contracts are stated at fair value in the accompanying condensed consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of
September 30, 2018
and
December 31, 2017
, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross Fair Value
|
|
Netting
|
|
Carrying Value
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity derivatives
|
$
|
—
|
|
|
$
|
4,282
|
|
|
$
|
—
|
|
|
$
|
4,282
|
|
|
$
|
(4,079
|
)
|
|
$
|
203
|
|
Noncurrent commodity derivatives
|
—
|
|
|
908
|
|
|
—
|
|
|
908
|
|
|
(908
|
)
|
|
—
|
|
Total assets
|
$
|
—
|
|
|
$
|
5,190
|
|
|
$
|
—
|
|
|
$
|
5,190
|
|
|
$
|
(4,987
|
)
|
|
$
|
203
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity derivatives
|
$
|
—
|
|
|
$
|
(68,340
|
)
|
|
$
|
—
|
|
|
$
|
(68,340
|
)
|
|
$
|
4,079
|
|
|
$
|
(64,261
|
)
|
Noncurrent commodity derivatives
|
—
|
|
|
(19,809
|
)
|
|
—
|
|
|
(19,809
|
)
|
|
908
|
|
|
(18,901
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
(88,149
|
)
|
|
$
|
—
|
|
|
$
|
(88,149
|
)
|
|
$
|
4,987
|
|
|
$
|
(83,162
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross Fair Value
|
|
Netting
|
|
Carrying Value
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity derivatives
|
$
|
—
|
|
|
$
|
2,856
|
|
|
$
|
—
|
|
|
$
|
2,856
|
|
|
$
|
(2,704
|
)
|
|
$
|
152
|
|
Noncurrent commodity derivatives
|
—
|
|
|
2,182
|
|
|
—
|
|
|
2,182
|
|
|
(1,186
|
)
|
|
996
|
|
Total assets
|
$
|
—
|
|
|
$
|
5,038
|
|
|
$
|
—
|
|
|
$
|
5,038
|
|
|
$
|
(3,890
|
)
|
|
$
|
1,148
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity derivatives
|
$
|
—
|
|
|
$
|
(11,983
|
)
|
|
$
|
—
|
|
|
$
|
(11,983
|
)
|
|
$
|
2,704
|
|
|
$
|
(9,279
|
)
|
Noncurrent commodity derivatives
|
—
|
|
|
(2,557
|
)
|
|
—
|
|
|
(2,557
|
)
|
|
1,186
|
|
|
(1,371
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
(14,540
|
)
|
|
$
|
—
|
|
|
$
|
(14,540
|
)
|
|
$
|
3,890
|
|
|
$
|
(10,650
|
)
|
Non-Recurring Fair Value Measurements
The Company’s non‑recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations and the determination of the grant date fair value of the Company’s performance share units. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted‑cash flow approach using level 3 inputs. The fair value of assets or liabilities associated with purchase price allocations is on a non‑recurring basis and is not measured in periods after initial recognition. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer to
Note 4 – Acquisitions
and
Note 11 – Equity Compensation
for additional discussion.
Other Financial Instruments
The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates.
Note 10 – Equity
In September 2018 and in conjunction with the Reorganization, the Company issued
152.5 million
shares of its Class A common stock to the members of Roan LLC in exchange for their equity interest in Roan LLC. The Reorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the underlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the shares to the members of Roan LLC at the time of the Reorganization was reflected on a retroactive basis with the units outstanding during each period presented.
For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued
1.5 billion
membership units representing capital interests in Roan LLC (the "LLC Units") for a
50%
equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See
Note 4 – Acquisitions
for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued
1.5 billion
LLC Units, which represented a
50%
equity interest, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn.
As discussed in
Note 4 – Acquisitions
, Citizen and Linn acquired acreage during 2017 on Roan LLC’s behalf. In March 2018, Roan LLC issued
19.2 million
LLC Units to each Citizen and Linn for the additional leasehold acreage.
For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the “Citizen Operating Agreement”), effective February 29, 2016, and Citizen had
two
classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Class A and Class B members pro rata in accordance with their membership interests; however, once the Class A members received an internal rate of return threshold of
9%
prior to distributions to any other class of interest, the Class B members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.
Note 11 – Equity Compensation
The Company has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards.
Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the “PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from
0%
to
200%
based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the
30
consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs.
The following table summarizes information related to the total number of PSUs awarded as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
PSUs
|
|
Weighted
Average Fair
Value
|
|
Total Fair
Value ($ in thousands)
|
PSUs outstanding at December 31, 2017
|
16,350,000
|
|
|
$
|
1.41
|
|
|
$
|
23,054
|
|
PSUs granted
|
6,825,000
|
|
|
$
|
1.88
|
|
|
$
|
12,810
|
|
PSUs vested
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Conversion
(1)
|
(22,016,250
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
PSUs outstanding at September 30, 2018
|
1,158,750
|
|
|
$
|
30.95
|
|
|
$
|
35,864
|
|
(1)
PSUs were converted on a basis of
0.05
to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification.
Compensation expense associated with the PSUs for the
three and nine
months ended
September 30, 2018
was
$2.9 million
and
$8.1 million
, respectively, and is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. Unrecognized expense as of
September 30, 2018
for all outstanding PSU awards was
$27.4 million
and will be recognized over a weighted-average remaining period of
2.25
years. Under the treasury stock method, the PSUs are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying condensed consolidated statements of operations.
The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date.
The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the following periods:
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2018
|
Three Months Ended September 30, 2018
|
Company enterprise value (in billions)
|
$
|
4.56
|
|
$
|
4.19
|
|
Equity volatility
|
34.0
|
%
|
36.0
|
%
|
Weighted average risk-free interest rate
|
1.96
|
%
|
2.54
|
%
|
Note 12 –Transactions with Affiliates
Management Service Agreements
Under the MSAs, Citizen and Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collected amounts due from joint interest
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
owners for their share of costs and billed the Company for its share of costs. The services provided under the MSAs ended in April 2018 when the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn.
For the
nine months ended September 30, 2018
, the Company incurred approximately $
10.0 million
in charges related to the services provided under the MSAs, which are recorded in general and administrative expenses in the accompanying condensed consolidated statements of operations. Since the MSA ended in April 2018, there were
no
such charges related to the MSA in the
three months ended September 30, 2018
.
Through April 2018, Citizen and Linn billed the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had
$55.5 million
and
$46.5 million
due to Linn and Citizen, respectively, included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets. At December 31, 2017, the Company had
$19.0 million
due to Linn and Citizen for revenue suspense associated with the oil and natural gas properties contributed to the Company included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets.
Acquisition of Acreage
As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the Company. As of December 31, 2017, the additional acreage acquired totaled
$63.0 million
and the Company reflected the amount due to Citizen and Linn in accounts payable and accrued liabilities – affiliates. See
Note 4 – Acquisitions
and
Note 10 – Equity
for further discussion of the settlement of the payable due to Citizen and Linn related to the additional acquired acreage.
Natural Gas Dedication Agreement
The Company has a gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), a subsidiary of Riviera Resources, Inc. (“Riviera”), which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at
September 30, 2018
and December 31, 2017 are reflected as accounts receivable – affiliates in the accompanying condensed consolidated balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as natural gas sales – affiliates and NGL sales – affiliates in the accompanying condensed consolidated statements of operations. See further discussion of this gas dedication agreement in
Note 14 – Commitments and Contingencies
.
Corporate Office Lease
During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of
5 years
. The Company paid
$0.4 million
during the
nine months ended September 30, 2018
under this lease. Total remaining payments under the lease are
$8.3 million
.
Tax Matters Agreement
In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. See
Note 13 – Income Taxes
for further discussion of the TMA and the related payable to Riviera.
Roan Resources LLC
Notes to Financial Statements
Note 13 – Income Taxes
As discussed in
Note 1 – Business and Organization
, the Company was formed in September 2018 in connection with the Reorganization. The Company’s accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members.
A deferred tax liability was recorded as a result of the Reorganization based on the Company being taxable as a corporation under the Internal Revenue Code of 1986, as amended.
The initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization was reflected in income tax expense based on the deferred tax liability resulting from the change in tax status. Due to the nontaxable nature of the Reorganization, there were no adjustments to the tax basis or other tax attributes in the measurement of the deferred taxes except to the extent any gain was recognized by the other parties to the Reorganization.
The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.
The Company’s effective combined U.S. federal and state income tax rate for the nine months ended September 30, 2018 excluding discrete items was
25.5%
. During the third quarter of 2018, the Company recognized income tax expense of
$299.7 million
, primarily representing
the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization.
In conjunction with the Reorganization, the Company entered into a TMA with Riviera. The TMA, in part, provides for indemnification of the Company and entitlement of refunds by Riviera of certain taxes related to Linn Energy, Inc. prior to the spinoff of assets from Linn Energy, Inc. to Riviera. As a result of the TMA and an estimated overpayment of federal taxes by Linn Energy, Inc., the Company has recorded a
$7.7 million
income tax receivable and a payable of
$7.7 million
to Riviera at
September 30, 2018
. The receivable is included in accounts receivable - other and the payable is included in accounts payable and accrued liabilities - affiliates in the accompanying condensed consolidated balance sheets.
The Company’s deferred tax liabilities as of
September 30, 2018
include the following (in thousands):
|
|
|
|
|
Deferred income tax assets (liabilities):
|
|
Oil and natural gas properties
|
$
|
(322,911
|
)
|
Derivative contracts
|
22,530
|
|
Other
|
719
|
|
Deferred tax liabilities, net
|
$
|
(299,662
|
)
|
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 14 – Commitments and Contingencies
Litigation
In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At
September 30, 2018
, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Natural Gas Dedication Agreements
The Company has dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.
For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.
Volume Commitment
Under an agreement with a third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any undelivered volumes as of November 2021. If the Company was unable to deliver any additional natural gas volumes, it would owe deficiency fees of
$8.6 million
as of September 30, 2018. Based on natural gas volumes delivered as of September 30, 2018, current production from producing wells and expected production from wells planned to be drilled in the specified area, the Company expects to meet the required minimum volume commitment.
Note 15 – Subsequent Events
Subsequent to
September 30, 2018
, the Company entered into fixed price swaps for
2,500
Bbls per day of NGL production at a weighted average price of
$34.03
for the period of October 2018 to December 2019 and for
20,000
Mcf per day of natural gas production at a weighted average price of
$2.93
for the period of January 2019 to December 2019.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of the financial condition and results of the Company should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this report as well as our audited consolidated financial statements and notes included in
o
ur Current Report on Form 8-K filed September 24, 2018. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are subject to risk and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. Please refer to Part II, Item 1A. “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for additional information regarding these risks and uncertainties. In light of these risks and uncertainties, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Roan Inc. was incorporated in September 2018 to serve as a holding company, and prior to the Reorganization, had no previous operations, assets or liabilities. The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor. The historical financial and operating information of Roan LLC presented here, (i) prior to August 31, 2017, the date of the completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the operating information of Citizen prior to August 31, 2017 does not include financial information relating to the oil and natural gas properties contributed by Linn.
Overview
We are an independent oil and natural gas company focused on the development of our assets throughout the eastern and southern Anadarko Basin. The Anadarko Basin, which spans from south-central Oklahoma to the northeast corner of the Texas panhandle, is one of the largest and most prolific onshore oil and natural gas basins in the United States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of development. We focus our development on formations where we believe we can apply our technical and operational expertise in order to increase production and cash flow to deliver compelling economic rates of return on a risk adjusted basis. Our objective is to maximize shareholder value and corporate returns by generating steady production growth, strong pre-tax margins and significant cash flow.
Our primary developmental focus is on our Merge acreage position in Canadian, Grady and McClain counties in Central Oklahoma. We are one of the most active operators in Oklahoma, with eight rigs actively operating as of
September 30, 2018
, all of which are focused on drilling horizontal well laterals in the Merge and SCOOP plays. Our acreage position is concentrated in what we believe are the oil and liquids-rich fairways of the Merge play and provides us development opportunities through multiple stacked prospective development horizons.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
|
|
•
|
actual and projected reserve and production levels;
|
|
|
•
|
realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
|
|
|
•
|
lease operating expenses; and
|
|
|
•
|
capital expenditures on our oil and natural gas properties.
|
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Corporate Reorganization
On September 24, 2018, we completed the Reorganization, where Roan LLC, our accounting predecessor, became a wholly owned subsidiary of Roan Inc. Roan Inc. was incorporated to serve as a holding company and, prior to the Reorganization, had no previous operations, assets or liabilities. For more information on our Reorganization, please see
Note 1 – Business and Organization
.
The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor. The historical financial and operating information of Roan LLC presented here, (i) prior to August 31, 2017, the date of the completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the operating information of Citizen prior to August 31, 2017 does not include financial information relating to the oil and natural gas properties contributed by Linn.
Income Taxes
As a result of the Reorganization, we became subject to federal and state tax. Due to the change in tax status, we have recorded a tax provision for the initial recording of the deferred tax liability recognized as a result of the Reorganization. Our accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members.
Impact of ASC Topic 606 Adoption
Revenue for the three and nine months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. For a discussion of the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standards, see
Note 3 – Revenue from Contracts with Customers
.
Financial and Operational Performance
Our financial and operational performance for the
nine months ended September 30, 2018
included the following highlights:
|
|
•
|
Net loss was
$288.9 million
for the
nine months ended September 30, 2018
, as compared to net income of
$28.8 million
for the
nine months ended September 30, 2017
. The net loss was primarily due to:
|
|
|
•
|
$100.9 million
loss on derivative contracts during the
nine months ended September 30, 2018
as a result of increases in oil prices during this period;
|
|
|
•
|
$19.7 million
increase
in production expenses, primarily related to an increase in production volumes for the nine months ended September 30, 2018;
|
|
|
•
|
$25.7 million
increase
in exploration expenses, primarily related to increased unproved leasehold amortization during the
nine months ended September 30, 2018
;
|
|
|
•
|
$61.5 million
increase
in depreciation, depletion, amortization and accretion, primarily due to increased production volumes and a higher depletion rate due to increases in capital expenditures;
|
|
|
•
|
$18.2 million
increase
in general & administrative expenses, primarily due to fees paid to Citizen and Linn under MSAs, salaries and benefits to our employees and equity-based compensation expense during the
nine months ended September 30, 2018
; and
|
|
|
•
|
$299.7 million
income tax expense during the
nine months ended September 30, 2018
as a result of recognizing a deferred tax liability upon becoming a taxable entity after the Reorganization.
|
Partially offset by:
|
|
•
|
$213.1 million
increase
in oil, natural gas and NGL sales, primarily as a result of an
increase
in total production volumes during the nine months ended September 30, 2018.
|
|
|
•
|
Average daily sales volumes were
40.1
MBoe for the
nine months ended September 30, 2018
, an increase of
208%
compared to
13.0
MBoe during 2017.
|
|
|
•
|
Drilled or participated in 165 gross (51 net) wells in the first nine months of 2018.
|
|
|
•
|
1,246 gross (502 net) producing wells online at
September 30, 2018
, including 584 gross (430 net) operated wells.
|
|
|
•
|
Our Class A common stock began trading on the New York Stock Exchange (“NYSE”) under the ticker symbol “ROAN” on November 9, 2018. Upon trading on the NYSE, our Class A common stock ceased trading on the OTCQB market.
|
Sources of Revenue
Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. For the nine months ended
September 30, 2018
, our revenues, excluding loss on derivative contracts, were derived
63%
from oil sales,
16%
from natural gas sales and
21%
from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Realized Prices on the Sales of Oil, Natural Gas and NGL Volumes
Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and NGLs, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. From time to time, we enter into derivative arrangements for our oil and natural gas production to mitigate the impact of price volatility on our business. See
Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk
for further discussion of the risks related to commodity price exposure and our derivative contracts.
Pricing for certain of our natural gas contracts are based on Oklahoma indexes, including ONEOK Gas Transportation (“OGT”), Natural Gas Pipeline Company of America Mid-Continent (“NGPL MC”), Panhandle Eastern Pipeline (“PEPL”) and Southern Star Central Gas Pipeline (“SSCGP”) due to the proximity of those pipelines to our producing properties. These indexes fluctuate from Henry Hub pricing due to a variety of reasons including the distance to the retail market, availability and capacity of pipelines to move the product to distribution hubs, customer demand, and competition between suppliers.
Oil and natural gas prices have been subject to significant fluctuations during the past several years. The average oil prices were higher while the average natural gas prices remained consistent during the three and nine months ended September 30,
2018
compared to the same periods in
2017
. The following table sets forth the average NYMEX oil and natural gas prices for the
three and nine
months ended
September 30, 2018
and
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Average NYMEX prices
|
|
|
|
|
|
|
|
Oil (Bbl)
|
$
|
69.55
|
|
|
$
|
48.21
|
|
|
$
|
66.75
|
|
|
$
|
49.47
|
|
Natural gas (MMcf)
|
$
|
3.04
|
|
|
$
|
3.06
|
|
|
$
|
3.06
|
|
|
$
|
3.12
|
|
Results of Operations
Three Months Ended
September 30, 2018
Compared to Three Months Ended
September 30, 2017
The following table presents selected financial and operating information for the periods presented.
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
2018
|
|
2017
|
Production Data
|
|
|
|
Oil (MBbls)
|
1,089
|
|
|
348
|
|
Natural gas (MMcf)
|
11,417
|
|
|
4,709
|
|
Natural gas liquids (MBbls)
|
1,286
|
|
|
405
|
|
Total volumes (MBoe)
|
4,278
|
|
|
1,538
|
|
Average daily total volumes (MBoe/d)
|
46.5
|
|
|
16.7
|
|
Average Prices - as reported
(1)
|
|
|
|
Oil (per Bbl)
|
$
|
68.86
|
|
|
$
|
47.99
|
|
Natural gas (per Mcf)
|
$
|
1.58
|
|
|
$
|
2.73
|
|
Natural gas liquids (per Bbl)
|
$
|
21.08
|
|
|
$
|
24.87
|
|
Total (per Boe)
|
$
|
28.09
|
|
|
$
|
25.76
|
|
Average Prices - including impact of derivative contract settlements
(1)(2)
|
|
|
Oil (per Bbl)
|
$
|
55.71
|
|
|
$
|
47.99
|
|
Natural gas (per Mcf)
|
$
|
1.62
|
|
|
$
|
2.73
|
|
Natural gas liquids (per Bbl)
|
$
|
21.08
|
|
|
$
|
24.87
|
|
Total (per Boe)
|
$
|
24.83
|
|
|
$
|
25.76
|
|
Average Prices - excluding gathering, transportation and processing costs
(3)
|
|
|
Oil (per Bbl)
|
$
|
68.93
|
|
|
$
|
47.99
|
|
Natural gas (per Mcf)
|
$
|
1.90
|
|
|
$
|
2.73
|
|
Natural gas liquids (per Bbl)
|
$
|
27.37
|
|
|
$
|
24.87
|
|
Total (per Boe)
|
$
|
30.86
|
|
|
$
|
25.76
|
|
|
|
(1)
|
Average prices for the three months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
|
|
(2)
|
Excludes settlement of derivative contracts prior to their contractual maturity.
|
|
|
(3)
|
Excludes the effects of netting gathering, transportation and processing costs under ASC 606.
|
Revenues
Our operating revenues includes revenues from the sale of oil, natural gas and NGLs and gain (loss) on our derivative contracts. The following table provides information on our operating revenues:
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
2018
|
|
2017
|
Revenues
|
(in thousands)
|
Oil sales
(1)
|
$
|
74,987
|
|
|
$
|
16,701
|
|
Natural gas sales
(1)
|
18,059
|
|
|
12,845
|
|
Natural gas liquid sales
(1)
|
27,106
|
|
|
10,074
|
|
(Loss) gain on derivative contracts
|
(36,704
|
)
|
|
131
|
|
Total revenues
|
$
|
83,448
|
|
|
$
|
39,751
|
|
|
|
(1)
|
Revenue for the three months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
Oil sales.
Our oil sales
increased
by approximately
$58.3 million
, or
349%
, to
$75.0 million
for the three months ended
September 30, 2018
from
$16.7 million
for the three months ended
September 30, 2017
. This
increase
was primarily due to the
increase
in production as well as the
increase
in average sales prices received for those produced volumes. Our oil production
increased
741
MBbls, or
213%
, to
1,089
MBbls for the three months ended
September 30, 2018
from
348
MBbls for the three months ended
September 30, 2017
. The
increase
in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The
increase
in average sales prices received on our oil production for the three months ended
September 30, 2018
reflects the
increase
in the index price for oil in the 2018 period as compared to the 2017 period.
Natural Gas sales.
Our natural gas sales
increased
by approximately
$5.2 million
, or
41%
, to
$18.1 million
for the three months ended
September 30, 2018
from
$12.8 million
for the three months ended
September 30, 2017
. This
increase
was primarily due to the
increase
in production partially offset by the
decrease
in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production
increased
6,708
MMcf, or
142%
, to
11,417
MMcf for the three months ended
September 30, 2018
from
4,709
MMcf for the three months ended
September 30, 2017
. The
increase
in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The
decrease
in average sales prices received on our natural gas production for the three months ended
September 30, 2018
reflects the
decrease
in the Oklahoma index prices we received under our contract terms for natural gas in the 2018 period as compared to the 2017 period.
NGL sales.
Our NGL sales
increased
by approximately
$17.0 million
, or
169%
, to
$27.1 million
for the three months ended
September 30, 2018
from
$10.1 million
for the three months ended
September 30, 2017
. This
increase
was primarily due to the
increase
in production and an
increase
in the average sales prices received for those produced volumes, partially offset by the impact of netting of transportation costs with revenue as a result of adopting ASC 606. Our NGL production
increased
881
MBbls, or
218%
, to
1,286
MBbls for the three months ended
September 30, 2018
from
405
MBbls for the three months ended
September 30, 2017
.
The
increase
in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018.
(Loss) gain on derivative contracts.
For the three months ended
September 30, 2018
, changes in oil prices had a negative impact on the fair value and settlement of our derivative contracts. We had a loss on derivative contracts of
$36.7 million
, including loss on settlement of derivatives contracts of
$13.6 million
and unfavorable change in the fair value of derivative contracts of
$23.1 million
. For the three months ended
September 30, 2017
, we had a gain on derivative contracts of
$0.1 million
related to the settlement of derivative contracts prior to their contractual maturity.
Operating Expenses
Our operating expenses reflect costs incurred in the development, production and sale of oil, natural gas and NGLs. The following table provides information on our operating expenses:
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
2018
|
|
2017
|
|
(in thousands, except costs per Boe)
|
Operating Expenses
|
|
|
|
Production expenses
|
$
|
14,737
|
|
|
$
|
4,336
|
|
Gathering, transportation and processing
(1)
|
—
|
|
|
4,890
|
|
Production taxes
|
6,210
|
|
|
847
|
|
Exploration expenses
|
11,646
|
|
|
4,229
|
|
Depreciation, depletion, amortization and accretion
|
37,164
|
|
|
10,824
|
|
General and administrative
(2)
|
13,177
|
|
|
4,489
|
|
Gain on sale of oil and natural gas properties
|
—
|
|
|
(838
|
)
|
Total
|
$
|
82,934
|
|
|
$
|
28,777
|
|
Average Costs per Boe
|
|
|
|
Production expenses
|
$
|
3.44
|
|
|
$
|
2.82
|
|
Gathering, transportation and processing
(1)
|
—
|
|
|
3.18
|
|
Production taxes
|
1.45
|
|
|
0.55
|
|
Exploration expenses
|
2.72
|
|
|
2.75
|
|
Depreciation, depletion, amortization and accretion
|
8.69
|
|
|
7.04
|
|
General and administrative
(2)
|
3.08
|
|
|
2.92
|
|
Gain on sale of oil and natural gas properties
|
—
|
|
|
(0.54
|
)
|
Total
|
$
|
19.38
|
|
|
$
|
18.72
|
|
|
|
(1)
|
Gathering, transportation and processing for the three months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
|
|
(2)
|
General and administrative expenses for the three months ended
September 30, 2018
include
$2.9 million
, or
$0.69
per Boe, of equity-based compensation expense.
|
Production expenses.
Production expenses are the operating costs incurred to maintain production. Such costs include the cost of saltwater disposal, monitoring, pumping, chemicals, maintenance, repairs, workover expenses and direct labor and overhead related to production activities. Production expenses were
$14.7 million
, or $
3.44
per Boe, for the three months ended
September 30, 2018
, which was an
increase
of
$10.4 million
, or
240%
, from
$4.3 million
for the three months ended
September 30, 2017
. The
increase
in production expenses during 2018 compared to 2017 was primarily due to
increased
production. The
increase
in production expenses per Boe was primarily driven by increases in maintenance and surface repairs incurred during the three months ended September 30, 2018.
Gathering, transportation and processing.
These costs are incurred to get oil, natural gas and NGLs to market. Gathering, transportation, and processing costs were
$4.9 million
, or $
3.18
per Boe, for the three months ended
September 30, 2017
. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from revenue for the three months ended
September 30, 2018
.
Production taxes.
Production taxes are paid on produced oil, natural gas, and NGLs based primarily on a percentage of sales revenues from production sold at fixed rates established by federal, state or local taxing authorities. Production taxes were
$6.2 million
for the three months ended
September 30, 2018
, an
increase
of
$5.4 million
, or
633%
, from
$0.8 million
for the three months ended
September 30, 2017
. Production taxes primarily
increased
due to
increased
revenues and increased production tax rates, which became effective in July 2018.
Exploration expenses.
These are primarily geological and geophysical costs that include seismic survey costs, amortization of the costs of unproved properties assessed for impairment on a group basis, costs of carrying and retaining unproved properties, and costs related to unsuccessful leasing efforts. For the three months ended
September 30, 2018
, exploration expenses of
$11.6 million
primarily consisted of unproved leasehold amortization. Unproved leasehold amortization is calculated by considering our drilling plans and the lease terms of our existing unproved properties. For the three months ended
September 30, 2017
, exploration expenses of
$4.2 million
consisted of impairment expense recognized related to our unproved properties. The
increase
in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Linn.
Depreciation, depletion, amortization and accretion.
Depreciation, depletion, amortization and accretion was
$37.2 million
, or $
8.69
per Boe, for the three months ended
September 30, 2018
, compared to
$10.8 million
, or $
7.04
per Boe, for the three months ended
September 30, 2017
, which is an
increase
of
$26.3 million
or
243%
. The
increase
in depreciation, depletion, amortization and accretion was primarily due to increased production.
General and administrative.
General and administrative expenses were
$13.2 million
, or $
3.08
per Boe, for the three months ended
September 30, 2018
, an
increase
of
$8.7 million
or
194%
from
$4.5 million
, or $
2.92
per Boe, for the three months ended
September 30, 2017
. During the three months ended
September 30, 2018
, general and administrative expenses included salaries and benefits of
$6.9 million
and equity-based compensation expense of
$2.9 million
. There were no such expenses incurred in the three months ended
September 30, 2017
. These expenses were offset by fees paid to Citizen and Linn under the MSAs of $2.5 million during the three months ended
September 30, 2017
. The MSAs with Citizen and Linn concluded in April 2018.
Other Expenses
Interest expense, net.
Interest expense, net of capitalized interest, for the three months ended
September 30, 2018
was
$2.1 million
as compared to
$0.3 million
for the three months ended
September 30, 2017
. This
increase
was due to increased borrowings outstanding during the three months ended
September 30, 2018
as compared to the three months ended
September 30, 2017
.
Income tax expense.
Income tax expense for the three months ended
September 30, 2018
was
$299.7 million
and relates to the recognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization.
Nine Months Ended September 30, 2018
Compared to
Nine Months Ended September 30, 2017
The following table presents selected financial and operating information for the periods presented.
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
Production Data
|
|
|
|
Oil (MBbls)
|
3,004
|
|
|
884
|
|
Natural gas (MMcf)
|
29,486
|
|
|
10,523
|
|
Natural gas liquids (MBbls)
|
3,042
|
|
|
911
|
|
Total volumes (MBoe)
|
10,960
|
|
|
3,549
|
|
Average daily total volumes (MBoe/d)
|
40.1
|
|
|
13.0
|
|
Average Prices - as reported
(1)
|
|
|
|
Oil (per Bbl)
|
$
|
65.70
|
|
|
$
|
51.70
|
|
Natural gas (per Mcf)
|
$
|
1.66
|
|
|
$
|
2.93
|
|
Natural gas liquids (per Bbl)
|
$
|
21.49
|
|
|
$
|
24.20
|
|
Total (per Boe)
|
$
|
28.44
|
|
|
$
|
27.79
|
|
Average Prices - including impact of derivative contract settlements
(1)(2)
|
|
|
|
Oil (per Bbl)
|
$
|
55.70
|
|
|
$
|
51.70
|
|
Natural gas (per Mcf)
|
$
|
1.73
|
|
|
$
|
2.95
|
|
Natural gas liquids (per Bbl)
|
$
|
21.49
|
|
|
$
|
24.20
|
|
Total (per Boe)
|
$
|
25.90
|
|
|
$
|
27.83
|
|
Average Prices - excluding gathering, transportation and processing costs
(3)
|
|
|
Oil (per Bbl)
|
$
|
65.72
|
|
|
$
|
51.70
|
|
Natural gas (per Mcf)
|
$
|
2.07
|
|
|
$
|
2.93
|
|
Natural gas liquids (per Bbl)
|
$
|
27.53
|
|
|
$
|
24.20
|
|
Total (per Boe)
|
$
|
31.21
|
|
|
$
|
27.79
|
|
|
|
(1)
|
Average prices for the nine months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
|
|
(2)
|
Excludes settlement of derivative contracts prior to their contractual maturity.
|
|
|
(3)
|
Excludes the effects of netting gathering, transportation and processing costs under ASC 606.
|
Revenues
The following table provides information on our operating revenues:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
(in thousands)
|
Revenues
|
|
|
|
Oil sales
(1)
|
$
|
197,356
|
|
|
$
|
45,702
|
|
Natural gas sales
(1)
|
48,956
|
|
|
30,884
|
|
Natural gas liquid sales
(1)
|
65,377
|
|
|
22,049
|
|
(Loss) gain on derivative contracts
|
(100,920
|
)
|
|
2,385
|
|
Total revenues
|
$
|
210,769
|
|
|
$
|
101,020
|
|
|
|
(1)
|
Revenue for the nine months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
Oil Sales.
Our oil sales
increased
by approximately
$151.7 million
, or
332%
, to
$197.4 million
for the
nine months ended September 30, 2018
from
$45.7 million
for the
nine months ended September 30, 2017
. This
increase
was primarily due to the
increase
in production as well as the
increase
in average sales prices received for our produced volumes. Our oil production
increased
2,120
MBbls, or
240%
, to
3,004
MBbls for the
nine months ended September 30, 2018
from
884
MBbls for the
nine months ended September 30, 2017
. The
increase
in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The
increase
in average sales prices received on our oil production for the
nine months ended September 30, 2018
reflects the
increase
in the index price for oil in the 2018 period as compared to the 2017 period.
Natural Gas Sales.
Our natural gas sales
increased
by approximately
$18.1 million
, or
59%
, to
$49.0 million
for the
nine months ended September 30, 2018
from
$30.9 million
for the
nine months ended September 30, 2017
. This
increase
was primarily due to the
increase
in production, partially offset by a
decrease
in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production
increased
18,963
MMcf, or
180%
, to
29,486
MMcf for the
nine months ended September 30, 2018
from
10,523
MMcf for the
nine months ended September 30, 2017
. The
increase
in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The
decrease
in average sales prices received on our natural gas production for the
nine months ended September 30, 2018
reflects the
decrease
in the Oklahoma index prices we received under our contract terms for natural gas in the 2018 period as compared to the 2017 period.
NGL Sales.
Our NGL sales
increased
by approximately
$43.3 million
, or
197%
, to
$65.4 million
for the
nine months ended September 30, 2018
from
$22.0 million
for the
nine months ended September 30, 2017
. This
increase
was primarily due to the
increase
in production and an
increase
in the average sales prices received for those produced volumes, partially offset by the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our NGL production
increased
2,131
MBbls, or
234%
, to
3,042
MBbls for the
nine months ended September 30, 2018
from
911
MBbls the
nine months ended September
30, 2017
. The
increase
in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018.
(Loss) gain on derivative contracts.
For the
nine months ended September 30, 2018
, changes in oil prices had a negative impact on the fair value and settlement of our derivative contracts. We had a
loss
on derivative contracts of
$100.9 million
, including loss on settlement of derivatives contracts of
$27.5 million
and unfavorable change in the fair value of derivative contracts of
$73.4 million
. The loss on settlement of derivative contracts included
$0.4 million
net loss on settlement of derivative contracts prior to their maturity. We had a
gain
on derivative contracts of
$2.4 million
during the
nine months ended September 30, 2017
which included
$2.3 million
related to the settlement of derivative contracts prior to their contractual maturity.
Operating Expenses
The following table provides information on our operating expenses:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
(in thousands, except per Boe)
|
Operating Expenses
|
|
|
|
Production expenses
|
$
|
30,111
|
|
|
$
|
10,450
|
|
Gathering, transportation and processing
(1)
|
—
|
|
|
11,360
|
|
Production taxes
|
10,892
|
|
|
2,057
|
|
Exploration expenses
|
30,129
|
|
|
4,475
|
|
Depreciation, depletion, amortization and accretion
|
83,630
|
|
|
22,176
|
|
General and administrative
(2)
|
40,283
|
|
|
22,062
|
|
Gain on sale of oil and natural gas properties
|
—
|
|
|
(838
|
)
|
Total
|
$
|
195,045
|
|
|
$
|
71,742
|
|
Average Costs per Boe
|
|
|
|
Production expenses
|
$
|
2.75
|
|
|
$
|
2.94
|
|
Gathering, transportation and processing
(1)
|
—
|
|
|
3.20
|
|
Production taxes
|
0.99
|
|
|
0.58
|
|
Exploration expenses
|
2.75
|
|
|
1.26
|
|
Depreciation, depletion, amortization and accretion
|
7.63
|
|
|
6.25
|
|
General and administrative
(2)
|
3.68
|
|
|
6.22
|
|
Gain on sale of oil and natural gas properties
|
—
|
|
|
(0.24
|
)
|
Total
|
$
|
17.80
|
|
|
$
|
20.21
|
|
|
|
(1)
|
Gathering, transportation and processing for the nine months ended
September 30, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
|
|
(2)
|
General and administrative expenses for the
nine months ended September 30, 2018
include
$8.1 million
, or
$0.74
per Boe, of equity-based compensation expense.
|
Production expenses.
Production expenses were
$30.1 million
, or $
2.75
per Boe, for the
nine months ended September 30, 2018
, which was an
increase
of
$19.7 million
, or
188%
, from
$10.5 million
, or $
2.94
per Boe, for the
nine months ended September 30, 2017
. The
increase
in production expenses during 2018 compared to 2017 was primarily due to
increased
production. Due to certain production expenses being fixed, the
increased
production resulted in a
decrease
in production expense per Boe.
Gathering, transportation and processing.
Gathering, transportation, and processing costs were
$11.4 million
, or $
3.20
per Boe, for the
nine months ended September 30, 2017
. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from revenue for the
nine months ended September 30, 2018
.
Production taxes.
Production taxes were
$10.9 million
for the
nine months ended September 30, 2018
, an
increase
of
$8.8 million
, or
430%
, from
$2.1 million
for the
nine months ended September 30, 2017
. Production taxes primarily increased due to increased revenues.
Exploration expenses.
For the
nine months ended September 30, 2018
, exploration expenses of
$30.1 million
primarily consisted of amortization of unproved leasehold. For the
nine months ended September 30, 2017
, exploration expenses of
$4.5 million
consisted of impairment expense recognized related to our unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Linn.
Depreciation, depletion, amortization and accretion.
Depreciation, depletion, amortization and accretion was
$83.6 million
, or $
7.63
per Boe, for the
nine months ended September 30, 2018
, and
$22.2 million
, or $
6.25
per Boe, for the
nine months ended September 30, 2017
, which is an
increase
of
$61.5 million
or
277%
. The
increase
in depreciation, depletion, amortization and accretion was primarily due to
increased
production and, to a lesser extent, an increase in the depletion rate for our oil and natural gas properties. The per Boe increase in the depletion rate is attributable to higher capital expenditures.
General and administrative.
General and administrative expenses were
$40.3 million
, or $
3.68
per Boe, for the
nine months ended September 30, 2018
, an
increase
of
$18.2 million
or
83%
from
$22.1 million
, or $
6.22
per Boe, for the
nine months ended September 30, 2017
. During the
nine months ended September 30, 2018
, general and administrative expenses included salaries and benefits of
$13.7 million
, equity-based compensation expense of
$8.1 million
and fees paid to Citizen and Linn under the MSAs of $10.0 million. Additionally, we incurred consulting and professional fees as part of the implementation of systems and processes and transition efforts in 2018. These expenses were offset by bonuses paid by Citizen of approximately $9.0 million and fees paid under the MSAs of $2.5 million during the
nine months ended September 30, 2017
. The MSAs with Citizen and Linn concluded in April 2018.
Other Expenses
Interest expense, net.
Interest expense, net of capitalized interest, for the
nine months ended September 30, 2018
was
$5.0 million
as compared to
$0.4 million
for the
nine months ended September 30, 2017
. This
increase
was due to
increased
borrowings outstanding during the
nine months ended September 30, 2018
as compared to the
nine months ended September 30, 2017
.
Income tax expense.
Income tax expense for the
nine months ended September 30, 2018
was
$299.7 million
and relates to the recognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization.
Liquidity and Capital Resources
Our primary sources of liquidity have been borrowings under our credit facility and cash flows from operations. Our primary uses of capital have been for the exploration, development and acquisition of oil and natural gas properties.
Cash Flows
Our cash flows for the
nine months ended September 30, 2018
and
2017
are presented below:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
(in thousands)
|
Net cash provided by operating activities
|
$
|
206,644
|
|
|
$
|
59,248
|
|
Net cash used in investing activities
|
(510,868
|
)
|
|
(182,571
|
)
|
Net cash provided by financing activities
|
306,653
|
|
|
117,410
|
|
Net increase (decrease) in cash and cash equivalents
|
$
|
2,429
|
|
|
$
|
(5,913
|
)
|
Cash flows provided by operating activities.
Cash flows provided by operating activities for the
nine months ended September 30, 2018
were
$206.6 million
compared to
$59.2 million
for the
nine months ended September 30, 2017
. The
increase
in cash flows provided by operating activities is primarily related to changes in working capital accounts and increased revenues partially offset by higher cash expenses due to increased activity in 2018.
Cash flows used in investing activities.
Cash flows used in investing activities for the
nine months ended September 30, 2018
were
$510.9 million
compared to
$182.6 million
for the
nine months ended September 30, 2017
. The increase in cash flows used in investing activities is due to the increase in capital expenditures on oil and natural gas properties resulting from the increase in drilling and completion activities in 2018 compared to 2017.
Cash flows provided by financing activities.
Cash flows provided by financing activities for the
nine months ended September 30, 2018
were
$306.7 million
compared to
$117.4 million
for the
nine months ended September 30, 2017
. The increase in cash flows provided by financing activities for the
nine months ended September 30, 2018
is attributable to borrowings of
$309.3 million
from our credit facility. Financing activity for the
nine months ended September 30, 2017
were related to capital contributions from Citizen members of
$95.6 million
and borrowings of
$75.3 million
, partially offset by distributions to Citizen members and repayments of
$40.0 million
on Citizen's credit facility.
Credit Facility
Our 2017 Credit Facility is a $750.0 million credit agreement with a maturity date of September 5, 2022. As of
September 30, 2018
, the borrowing base is set at $675.0 million. Redetermination of the borrowing base occurs semiannually on or about October 1 and April 1. As of
September 30, 2018
, we had
$394.6
million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility.
Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin (ranging from 2.00% to 3.00% for LIBOR and 1.00% to 2.00% for ABR), based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides
for a commitment fee of 0.375% to 0.50% based on utilization, which is payable at the end of each calendar quarter.
The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, we are prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon our internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, we are required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per our most recent reserve report.
The 2017 Credit Facility also contains financial covenants requiring us to comply with a leverage ratio of consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815
Derivatives and Hedging
and ASC Topic 410
Asset Retirement and Environmental Obligations
) as of the fiscal quarter ended of not less than 1.00 to 1.00.
As of
September 30, 2018
, we were in compliance with the covenants under the 2017 Credit Facility.
Capital Expenditures
Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow and financing under our 2017 Credit Facility.
Our capital budget for the fourth quarter of 2018 is $200 million to $225 million. During the
nine months ended September 30, 2018
, capital expenditures were
$558.0 million
. Capital expenditures include expenditures related to drilling and completion costs of
$474.7 million
, leasehold additions of
$73.5 million
, and other costs of
$9.8 million
which includes corporate spending on other property and equipment. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.
Based upon current oil and natural gas prices and production expectations for the remainder of 2018 and 2019, we believe our cash flow from operations, cash on hand, borrowings under our 2017 Credit Facility and access to capital markets will be sufficient to fund our operations for the next twelve months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties.
Working Capital
At
September 30, 2018
, we had a working capital deficit of
$183.1 million
compared to
$121.2 million
at December 31, 2017. Current assets and current liabilities
increased
by
$150.7 million
and
$212.6 million
, respectively, at
September 30, 2018
, compared to December 31, 2017 as a result of us taking over as operator in May 2018 on the oil and natural gas properties contributed to us by Citizen and Linn and increased drilling activity during 2018. Additionally, at the conclusion of the MSAs, we assumed certain working capital accounts associated with these properties from Citizen and Linn. Another factor contributing to the increase in the working capital deficit is the increase in the derivative contract liabilities of
$54.9 million
, which is due to the negative impact of higher in oil prices on the fair value of our open oil contracts with maturity dates in the next twelve months.
Off-Balance Sheet Arrangements
We enter into certain off-balance sheet arrangements and transactions, including operating lease arrangements and undrawn letters of credit. In addition, we enter into other contractual agreements in the normal course of business for processing and transportation as well as for other oil and natural gas activities. Other than the items discussed above, there are no other arrangements, transactions or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or capital resource positions.
Contractual Obligations
The following table summarizes our contractual obligations and commitments as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
2018
|
2019
|
2020
|
2021
|
2022
|
Thereafter
|
Total
|
|
(in thousands)
|
Credit Facility
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
394,639
|
|
$
|
—
|
|
$
|
394,639
|
|
Interest expenses related to Credit Facility
(1)
|
5,366
|
|
21,288
|
|
21,288
|
|
21,288
|
|
14,464
|
|
—
|
|
83,694
|
|
Pipe and equipment purchases commitments
(2)
|
1,925
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,925
|
|
Office building leases
|
489
|
|
1,677
|
|
2,047
|
|
2,136
|
|
2,229
|
|
627
|
|
9,205
|
|
Drilling rig commitments
(3)
|
8,050
|
|
15,352
|
|
—
|
|
—
|
|
—
|
|
—
|
|
23,402
|
|
Total contractual obligations and commitments
|
$
|
15,830
|
|
$
|
38,317
|
|
$
|
23,335
|
|
$
|
23,424
|
|
$
|
411,332
|
|
$
|
627
|
|
$
|
512,865
|
|
(1) Includes interest expense on our outstanding borrowings calculated using the weighted average interest rate of 5.32% at September 30, 2018.
(2) Reflects commitments to purchase specified amounts of pipe and equipment.
(3) Reflects future minimum drilling fees including early termination fees as specified by the contract.
The above table does not include liabilities related to ARO. These are costs associated with the plugging of wells and the related abandonment of oil and natural gas properties. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based on the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors
that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Although management believes they are reasonable, actual results could differ from these estimates and assumptions.
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see
Note 2 – Summary of Significant Accounting Policies
in the accompanying condensed consolidated financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to a number of market risks including commodity price risk, credit risk and interest rate risk. The following information provides quantitative and qualitative information about our potential risks and how we seek to manage such risks.
Commodity Price Risk
The following table reflects our open commodity contracts as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2019
|
|
2020
|
|
Total
|
Oil fixed prices swaps
|
|
|
|
|
|
|
|
Volume (Bbl)
|
1,233,180
|
|
|
5,540,670
|
|
|
1,599,500
|
|
|
8,373,350
|
|
Weighted-average price
|
$
|
57.09
|
|
|
$
|
59.86
|
|
|
$
|
63.14
|
|
|
$
|
60.08
|
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
8,004,000
|
|
|
29,200,000
|
|
|
12,325,000
|
|
|
49,529,000
|
|
Weighted-average price
|
$
|
2.94
|
|
|
$
|
2.86
|
|
|
$
|
2.63
|
|
|
$
|
2.81
|
|
Natural gas basis swaps
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
4,600,000
|
|
|
21,900,000
|
|
|
3,640,000
|
|
|
30,140,000
|
|
Weighted-average price
|
$
|
0.54
|
|
|
$
|
0.58
|
|
|
$
|
0.62
|
|
|
$
|
0.58
|
|
Our primary market risk exposure is in the price we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil and natural gas production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows. These derivatives are not designated as a hedging instrument for hedge accounting under GAAP and as such, gains or losses resulting from the change in fair value along with the gains or losses resulting from settlement of derivative contracts are reflected as gain or loss on derivative contracts included in the consolidated statement of operations.
There are a variety of hedging strategies and instruments used to hedge future price risk. We utilize fixed price swaps and basis swaps to manage the price risk associated with forecasted sale of our oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential. When the referenced settlement price is less than the price specified in the contract, we receive an amount from the counterparty based on the price difference multiplied by the volume. When the referenced settlement price exceeds the price
specified in the contract, we pay the counterparty an amount based on the price difference multiplied by the volume.
At
September 30, 2018
, we had a net liability position of
$83.0 million
related to our derivative contracts. Utilizing actual derivative contractual volumes under our fixed price swaps as of
September 30, 2018
, an increase of 10% in the forward curves associated with the underlying commodity would have increased the net liability position to $156.2 million, while a decrease of 10% in the forward curves associated with the underlying commodity would have resulted in a net liability position of $16.0 million.
Credit Risk
Our principal exposure to credit risk is through the sale of our oil, natural gas and NGL production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties.
We are subject to credit risk resulting from the concentration of oil, natural gas and NGL receivables with two significant purchasers. We do not believe the loss of any single purchaser would materially impact our results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.
Our derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. We monitor on an ongoing basis the credit ratings of our derivative counterparties and consider their credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. The counterparties to our derivative contracts at
September 30, 2018
, are also lenders under our 2017 Credit Facility. As a result, we do not require collateral or other security from counterparties nor are we required to post collateral to support derivative instruments. We have master netting agreements with all of our derivative counterparties, which allow us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our 2017 Credit Facility. The terms of our 2017 Credit Facility provide for interest on borrowings at LIBOR or the alternate base rate, in each case adjusted upward by an applicable margin based on the utilization percentage of the credit facility.
As of
September 30, 2018
, we had
$394.6 million
in outstanding borrowings under our 2017 Credit Facility. At September 30, 2018, the weighted average interest rate on borrowings under our 2017 Credit Facility was 5.32%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $3.9 million based on outstanding borrowings of
$394.6 million
under our 2017 Credit Facility as of
September 30, 2018
.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
.
As required by Rule 13a-15 and 15d-15 of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined
in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at September 30, 2018 at the reasonable assurance level because of the material weaknesses in our internal control over financial reporting as further described below.
Identification of Material Weaknesses
We have identified material weaknesses in our internal control over financial reporting in connection with the audit of our financial statements as of and for the years ended December 31, 2017 and 2016. A material weakness is a deficiency or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
We have identified five material weaknesses in our internal control over financial reporting. The material weaknesses identified relate to an overall lack of qualified personnel within the organization who possessed an appropriate level of expertise, experience and training to effectively design, implement and maintain: (i) adequate controls to monitor and assess the control environment. Specifically, internal controls were not designed or operating effectively to ensure appropriate monitoring or assessment of the control environment, including utilizing an appropriate control framework; (ii) adequate controls to establish appropriate entity level controls. Specifically, internal controls were not designed or operating effectively to ensure a sufficient amount of entity level controls were in place and operating effectively; (iii) effective controls over our period-end financial reporting processes, including controls over the preparation, analysis and review of certain significant account reconciliations required to assess the appropriateness of account balances at period-end; and controls over segregation of duties and the review of manual journal entries. Specifically, we did not design and maintain effective controls to verify that journal entries were properly prepared with sufficient supporting documentation or were reviewed and approved to ensure the accuracy and completeness of the manual journal entries. Additionally, certain key accounting personnel have the ability to prepare and post journal entries, as well as review account reconciliations, without an independent review by someone other than the preparer; and (iv) effective controls over information technology systems that are relevant to the preparation of the financial statements. Specifically, we did not design and maintain (a) user access controls to ensure appropriate segregation of duties and to adequately restrict user and privileged access to infrastructure, financial applications, programs, and data to appropriate personnel, (b) program change management controls to ensure that information technology program and data changes affecting financial IT applications and underlying accounting records are identified, tested, authorized and implemented appropriately, (c) computer operation controls to ensure all financially significant batch jobs are monitored for the completeness and accuracy of data transfer, and (d) program development controls to ensure that new software development is aligned with business and IT requirements. The deficiencies described in this clause (iv), when aggregated, could impact both maintaining effective segregation of duties and the effectiveness of IT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports) that could result in misstatements potentially impacting all financial statement accounts and disclosures that would not be prevented or detected in a timely manner; and (v) a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training to
develop and maintain an effective internal control environment. These material weaknesses originated with Citizen, the predecessor of Roan LLC, which had a lack of sufficient resources and inadequate control systems as it commenced operations as a private company. These material weaknesses did not result in any material misstatements of our financial statements or disclosures. The control deficiencies discussed above could result in a misstatement of account balances or disclosures that would result in a material misstatement to the annual or interim financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses.
Remediation Plan for the Material Weaknesses
We have taken and will continue to take a number of actions to remediate these material weaknesses. We are currently implementing measures designed to improve our internal control over financial reporting and remediate the control deficiencies that led to the material weaknesses, including but not limited to, (i) hiring additional IT and accounting personnel with appropriate technical skillsets, (ii) initiating design and implementation of our control environment, including the expansion of formal accounting and IT policies and procedures and financial reporting controls, (iii) conducting a company-wide assessment of our control environment, (iv) implementing appropriate review and oversight responsibilities within the accounting and financial reporting functions, and (v) evaluating controls over our information technology environment. We can give no assurance that these actions will remediate these material weaknesses in internal controls or that additional material weaknesses in our internal control over financial reporting will not be identified in the future.
Changes in Internal Control over Financial Reporting.
Except as described herein, there were no changes in our internal control over financial reporting during the quarter ended
September 30, 2018
, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.