NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Organization and Description of the Business
RSP Permian, Inc., a Delaware corporation ("RSP Inc.," the "Company," "we," "our," or "us"), is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin, both sub-basins of the Permian Basin. The Midland Basin properties are primarily in the adjacent counties of Midland, Martin, Andrews, Ector and Glasscock. The Delaware Basin properties are in Loving and Winkler counties. The Company’s common stock is listed and traded on the NYSE under the ticker symbol “RSPP.”
Basis of Presentation
These consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. The financial statements in this Quarterly Report on Form 10–Q should be read together with the financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2016
, which contains a complete summary of the Company’s significant accounting policies and disclosures.
Subsequent Events
The Company has evaluated events that occurred subsequent to
September 30, 2017
in preparing its consolidated financial statements. The Company determined there were no events, other than as described below, that required disclosure or recognition in these financial statements.
On October 19, 2017, the Company entered into a first amendment to our credit agreement, which, (a) increased the borrowing base to
$1.5 billion
from
$1.1 billion
, (b) maintained our elected commitment at
$900 million
and (c) decreased the applicable margins for interest rates applicable to amounts outstanding under the revolving credit facility from a range of
200
to
300
basis points above the applicable reference rate for Eurodollar loans and
100
to
200
basis points above the applicable reference rate for alternate base rate loans to ranges of
150
to
250
basis points for Eurodollar loans and
50
to
150
basis points for alternate base rate loans.
In November 2017, the Company exchanged
$450.0 million
of the
5.25%
senior unsecured notes for registered notes with the same terms.
During the fourth quarter of 2017, the Company has entered into derivative contracts covering
2.7 million
barrels of crude oil production beginning in the first quarter of 2018 through the fourth quarter of 2018, and now has derivative contracts covering
9.4 million
barrels of 2018 oil volumes. See Note 4 for a summary of derivative positions entered into subsequent to September 30, 2017.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations (“AROs”) and valuations of derivative instruments also require significant assumptions. It is possible that these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous
uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates. It is possible that these estimates could be revised at future dates and such revisions could be material.
Reclassifications
Certain reclassifications have been made to prior periods to conform to current period presentation. None of these reclassifications impacted previously reported equity, cash flows, or operating income amounts.
Accounts Receivable
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2017
|
|
As of December 31, 2016
|
|
|
(In thousands)
|
Sale of oil, natural gas liquids and natural gas
|
|
$
|
89,910
|
|
|
$
|
54,422
|
|
Joint interest owners
|
|
17,628
|
|
|
16,681
|
|
Federal income tax receivable
|
|
36
|
|
|
2,568
|
|
Total accounts receivable
|
|
$
|
107,574
|
|
|
$
|
73,671
|
|
Accounts receivable, which are primarily from the sale of oil, NGLs and natural gas, are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income tax receivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors. Bad debt expense was
zero
for each of the three and nine
months ended
September 30, 2017
and
2016
, respectively.
Oil and Natural Gas Properties
The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful.
The Company may capitalize interest on expenditures for significant exploration and development projects that last more than
six months
, while activities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less than
six months
. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred.
Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted on a field level, based on proved reserves, using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field level, based on proved developed reserves. For the
three months ended September 30, 2017
and
2016
, depletion expense for oil and natural gas property was
$72.7 million
and
$49.6 million
, respectively. For the
nine
months ended
September 30, 2017
and
2016
, depletion expense for oil and natural gas property was
$200.5 million
and
$140.7 million
, respectively.
Depletion expense is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.
The Company’s oil and natural gas properties as of
September 30, 2017
and
December 31, 2016
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
December 31, 2016
|
|
|
|
(In thousands)
|
Proved oil and natural gas properties
|
|
$
|
3,695,840
|
|
|
$
|
2,811,853
|
|
|
Unproved oil and natural gas properties
|
|
2,975,315
|
|
|
1,833,928
|
|
|
Total oil and natural gas properties
|
|
6,671,155
|
|
|
4,645,781
|
|
|
Less: Accumulated depletion
|
|
(717,958
|
)
|
|
(554,419
|
)
|
|
Total oil and natural gas properties, net
|
|
$
|
5,953,197
|
|
|
$
|
4,091,362
|
|
|
In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of
September 30, 2017
and
December 31, 2016
, there were
no
costs capitalized in connection with exploratory wells in progress.
Capitalized costs are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a field is impaired, the Company compares the carrying value of the field to the undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimates of proved reserves and risk-adjusted probable reserves.
For a property determined to be impaired, an impairment loss equal to the difference between the property’s carrying value and its estimated fair value is recognized. Fair value, on a field basis, is estimated to be the present value of the aforementioned expected future net cash flows. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value.
No
impairment of proved property was recorded for the
nine months ended September 30, 2017
or
2016
. The calculation of expected future net cash flows in impairment evaluations are mainly based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted reserves. The Company’s estimates for future oil and natural gas prices used in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties. If the prices used to assess our oil and natural gas properties for impairment were
15%
lower than the prices we used for such analysis, holding all other variables constant, we would not have expected to record any material impairment to our proved oil and natural gas properties. However, it is reasonably possible that oil and natural gas prices used in future impairment evaluations may decline, which could result in the need to impair the carrying value of the Company’s proved properties.
Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. For the
nine months ended September 30, 2017
and
2016
, impairment expense of unproved property was
$6.1 million
and
$4.3 million
, respectively, which primarily related to management’s expectation that certain leasehold interests would expire and not be renewed, along with certain leasehold interests that may expire or could otherwise be disposed of in the future.
Asset Retirement Obligation
The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.
The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of the surface acreage to a condition similar to that existing before oil and natural gas extraction began.
In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted
rate. If the estimated ARO changes, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
After recording these amounts, the ARO liability is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis.
The ARO liability consisted of the following for the period indicated:
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
(In thousands)
|
Asset retirement obligation at beginning of period
|
$
|
10,659
|
|
Liabilities incurred or assumed
|
2,031
|
|
Liabilities settled
|
(193
|
)
|
Accretion expense
|
454
|
|
Asset retirement obligation at end of period
|
$
|
12,951
|
|
Income Taxes
The following is an analysis of the Company’s consolidated income tax (expense) benefit for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
(In thousands)
|
Current (1)
|
|
$
|
7,423
|
|
|
$
|
7,369
|
|
|
$
|
5,288
|
|
|
$
|
7,369
|
|
Deferred (1)
|
|
(11,101
|
)
|
|
(3,862
|
)
|
|
(41,110
|
)
|
|
9,873
|
|
Income Tax (Expense) Benefit
|
|
$
|
(3,678
|
)
|
|
$
|
3,507
|
|
|
$
|
(35,822
|
)
|
|
$
|
17,242
|
|
(1) In the third quarter of 2017 and 2016, the Company recorded discrete deferred tax benefits associated with research and development credit claims, net of uncertain tax positions, of
$5.3 million
and
$2.4 million
, respectively.
Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2016, the Company had a long-term tax payable related to uncertain tax positions totaling
$5.3 million
. This amount was recorded in other long-term liabilities on the consolidated balance sheet. In the third quarter of 2017, the Company decreased the liability associated with uncertain tax positions to zero due to return to provision adjustments, which resulted in a current tax benefit offset by deferred tax expense with no impact to total tax expense.
The Company’s adoption of ASU 2016-09 in the first quarter of 2017 using the modified retrospective approach resulted in a decrease to deferred tax liability and a corresponding adjustment to accumulated deficit of
$0.6 million
as of December 31, 2016. Additional tax deductions during the nine months ended September 30, 2017 from stock compensation under the guidance of ASU 2016-09 resulted in a reduction to income tax expense of
$4.1 million
.
The Company’s U.S. federal income tax returns for 2013 and beyond, and its Texas franchise tax returns for 2012 and beyond, remain subject to examination by the taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. An entity is required to apply ASU 2014-09 for annual and interim reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a
modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company has selected the modified retrospective method and is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements; however, it has not identified any revenue stream that would be materially impacted and does not expect the adoption of this standard to have a material impact on our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)," which requires all lease transactions (with expected lease terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting," which simplifies several aspects of the accounting for share-based payment award transactions. These simplifications include the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The Company adopted this guidance in the first quarter of 2017 using the modified retrospective approach. Accordingly, the deferred tax liability at December 31, 2016 was reduced by
$0.6 million
with a corresponding adjustment to accumulated deficit in the consolidated balance sheet.
NOTE 3—ACQUISITIONS OF OIL AND NATURAL GAS PROPERTY INTERESTS
Silver Hill Acquisitions
On October 13, 2016, the Company entered into definitive agreements to acquire
100%
of Silver Hill Energy Partners, LLC (“SHEP I”) and Silver Hill E&P II, LLC (“SHEP II”, and together with SHEP I, “Silver Hill”) for an aggregate purchase price of
$1.25 billion
of cash and
31.0 million
shares of RSP Inc. common stock in aggregate. Silver Hill was comprised of
two
privately-held entities that collectively owned oil and gas producing properties and undeveloped acreage in Loving and Winkler counties in Texas and owned approximately
40,100
net acres. Silver Hill’s highly contiguous acreage position in the core of the Delaware Basin was complementary to the Company’s asset base and the acquisition creates substantial scale from a production and acreage standpoint.
The SHEP I acquisition closed on November 28, 2016, with cash consideration of
$604 million
, including assumed debt obligations which were repaid, before purchase price adjustments, and approximately
15.0 million
shares of RSP Inc. common stock. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to other assets.
The SHEP II acquisition closed on March 1, 2017, with cash consideration of
$646 million
, before purchase price adjustments, and approximately
16.0 million
shares of RSP Inc. common stock. A summary of the consideration transferred and the fair value of assets and liabilities acquired is as follows (in thousands, except shares):
|
|
|
|
|
Value of the Company’s common stock issued in the SHEP II acquisition (1)
|
$
|
663,854
|
|
Cash paid to sellers in the SHEP II acquisition (including deposit)
|
641,577
|
|
Total consideration for the assets contributed in the SHEP II acquisition
|
$
|
1,305,431
|
|
|
|
|
Fair value of oil and natural gas properties (2)
|
1,308,177
|
|
Asset retirement obligation
|
(822
|
)
|
Assumption of other liabilities
|
(1,924
|
)
|
Total net assets acquired
|
$
|
1,305,431
|
|
(1) The Company issued
16,019,638
shares of common stock at
$41.44
per share (closing price) on March 1, 2017.
(2) Approximately
77%
of the acquisition date fair value of oil and natural gas properties was recorded as unproved property.
The acquisition of SHEP II was accounted for using the acquisition method of accounting with the Company as the acquirer. Under the acquisition method of accounting, the Company recorded all assets acquired and liabilities assumed at their respective acquisition date fair values at the closing date of the acquisition. The fair values of the assets acquired and liabilities assumed are based on a detailed analysis, using industry accepted methods of estimating the current fair value as described below.
For the SHEP II acquisition, substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with no value ascribed to other assets. The Company used two valuation methods in its determination of fair value for the oil and gas properties: the discounted cash flow analysis and comparable transaction analysis. The significant assumptions included in the discounted cash flow analysis include commodity price assumptions, costs and capital outlay to develop the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing at the SHEP II acquisition date of March 1, 2017, less applicable pricing differentials, was utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis are determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined using the estimated weighted average cost of capital for the Company, discount rates published in third party publications, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly-situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions and the fair value calculation via the discounted cash flow method was used as a basis to determine fair value of the assets. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is substantially in the same range as the comparable transactions reviewed, when considering the comparable transactions on a median or average basis. Other current liabilities assumed in the SHEP II acquisition, which related to revenues held in suspense, were carried over at historical carrying values because the liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value.
Revenues and earnings of SHEP II recognized in 2017 subsequent to the acquisition date were
$46.7 million
and
$15.8 million
, respectively. The Company recognized
$4.5 million
of expenses related to the SHEP II acquisition in the first quarter of 2017, which are recorded in acquisition costs on the consolidated statement of operations.
Pro Forma Results
The Company’s summary pro forma results for the three and
nine
months ended
September 30, 2017
and 2016 were derived from the actual results of the Company adjusted to reflect the SHEP II acquisition, as if such transaction had occurred on January 1, 2016. The below information reflects pro forma adjustments for the issuance of common stock to the sellers of SHEP II along with common stock issued in the October 2016 public offering that funded the cash portion of the SHEP II acquisition. Additional pro forma adjustments, based on available information and certain assumptions, include (i) the depletion of SHEP II fair-valued proved oil and gas properties, and (ii) the estimated tax impacts of the pro forma adjustments. Pro forma earnings for the three and
nine
months ended
September 30, 2017
were adjusted to exclude
zero
and
$4.5 million
, respectively, of related acquisition costs incurred by the Company.
The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to the Company's actual and pro forma results for the periods reflected below and does not make any adjustments for non-recurring expenses associated with the SHEP II acquisition, except for the acquisition costs described above.
The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
Three Months Ended September 30, 2016
|
|
|
|
Actual
|
|
Pro Forma
|
|
Actual
|
|
Pro Forma
|
|
|
|
(In thousands, except per share data)
|
|
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
201,654
|
|
|
$
|
201,654
|
|
|
$
|
93,621
|
|
|
$
|
111,974
|
|
|
Net income
|
|
$
|
21,326
|
|
|
$
|
21,326
|
|
|
$
|
985
|
|
|
$
|
915
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.14
|
|
|
$
|
0.14
|
|
|
$
|
0.01
|
|
|
$
|
0.01
|
|
|
Diluted
|
|
$
|
0.14
|
|
|
$
|
0.14
|
|
|
$
|
0.01
|
|
|
$
|
0.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
Nine Months Ended September 30, 2016
|
|
|
|
Actual
|
|
Pro Forma
|
|
Actual
|
|
Pro Forma
|
|
|
|
(In thousands, except per share data)
|
|
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
554,685
|
|
|
$
|
573,404
|
|
|
$
|
230,922
|
|
|
$
|
266,950
|
|
|
Net income (loss)
|
|
$
|
91,350
|
|
|
$
|
99,810
|
|
|
$
|
(26,234
|
)
|
|
$
|
(33,889
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.59
|
|
|
$
|
0.65
|
|
|
$
|
(0.26
|
)
|
|
$
|
(0.34
|
)
|
|
Diluted
|
|
$
|
0.59
|
|
|
$
|
0.65
|
|
|
$
|
(0.26
|
)
|
|
$
|
(0.34
|
)
|
|
Other Acquisitions
During the third quarter of 2017, the Company closed on
two
acquisitions of undeveloped acreage and additional mineral interests in the Delaware Basin for an aggregate purchase price of approximately
$227.9 million
, before purchase price adjustments. These acquisitions were funded with borrowings under our revolving credit facility.
In addition to the acquisitions discussed above, in the first
nine
months of 2017, the Company closed on bolt-on acquisitions of mostly undeveloped acreage for an aggregate total purchase price of approximately
$37.2 million
. The acquisitions included additional working interests in properties where the Company owned existing interests as well as other properties in the Company’s core areas. These acquisitions were funded with cash on hand and borrowings under our revolving credit facility.
On January 2, 2017, the Company closed on the acquisition of water infrastructure assets from Lone Wolf Resources and related entities for an aggregate total purchase price of
$18.8 million
, before purchase price adjustments. The acquisition was funded with cash on hand.
NOTE 4—DERIVATIVE INSTRUMENTS
Commodity Derivative Instruments
The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil and natural gas production. These may include collar contracts, swaps, deferred premium put options and other related derivative structures. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings.
Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put as well. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is below the short put price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short put price multiplied by the hedged contract volume. Cumulatively, when the settlement price is below the short put price, the Company would receive from its counterparty an amount equal to the difference of the price floor and the short put price multiplied by the hedged contract volume.
Each deferred premium put option has an established floor price. When the settlement price is below the floor price, the Company receives the difference between the floor price and the settlement price multiplied by the hedged contract volume less the cost of the premium for the option. When the settlement price is at or above the floor price, the Company receives no proceeds and pays the cost of the premium for the option. In either case, whether the settlement price is below or above the floor price, the Company pays the premium for the option at the expiration of the option.
Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
The following table summarizes all commodity derivative positions as of
September 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts expiring in the period ending:
|
|
|
|
December 31, 2017
|
|
March 31, 2018
|
|
June 30, 2018
|
|
September 30, 2018
|
|
December 31, 2018
|
|
Crude Oil Three-Way Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
552,000
|
|
|
2,219,000
|
|
|
1,941,000
|
|
|
1,319,000
|
|
|
1,227,000
|
|
|
Weighted average ceiling price ($/Bbl)(1)
|
|
$
|
54.10
|
|
|
$
|
58.81
|
|
|
$
|
59.07
|
|
|
$
|
60.56
|
|
|
$
|
60.96
|
|
|
Weighted average floor price ($/Bbl)(1)
|
|
$
|
45.00
|
|
|
$
|
46.96
|
|
|
$
|
47.11
|
|
|
$
|
47.79
|
|
|
$
|
48.00
|
|
|
Weighted average short put price ($/Bbl)(1)
|
|
$
|
35.00
|
|
|
$
|
36.96
|
|
|
$
|
37.11
|
|
|
$
|
37.79
|
|
|
$
|
38.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Costless Collars:
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
1,150,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average ceiling price ($/Bbl)(1)
|
|
$
|
60.05
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average floor price ($/Bbl)(1)
|
|
$
|
45.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
552,000
|
|
|
|
|
|
|
|
|
|
|
Weighted average swap price ($/Bbl)(1)
|
|
$
|
48.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Deferred Premium Puts:
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
920,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average floor price ($/Bbl)(1)
|
|
$
|
48.50
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average deferred premium ($/Bbl) (2)
|
|
$
|
(4.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Cush Differential (Basis) Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
1,104,000
|
|
|
1,800,000
|
|
|
1,820,000
|
|
|
1,840,000
|
|
|
1,840,000
|
|
|
Weighted average swap price ($/Bbl)(4)
|
|
$
|
(0.63
|
)
|
|
$
|
(0.62
|
)
|
|
$
|
(0.62
|
)
|
|
$
|
(0.62
|
)
|
|
$
|
(0.62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Costless Collars:
|
|
|
|
|
|
|
|
|
|
|
|
Notional volume (MMBtu)
|
|
2,545,000
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average ceiling price ($/MMbtu)(3)
|
|
$
|
3.86
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average floor price ($/MMbtu)(3)
|
|
$
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude during the relevant period.
(2) The deferred premium is not paid until the expiration date, aligning cash inflows and outflows with the settlement of the derivative contract.
(3) The natural gas derivative contracts are settled based on the last trading day’s closing price for the front month contract relevant to each period.
(4) The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.
The following table summarizes all commodity derivative positions entered subsequent to September 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts expiring in the period ending:
|
|
|
|
March 31, 2018
|
|
June 30, 2018
|
|
September 30, 2018
|
|
December 31, 2018
|
|
Crude Oil Costless Collars:
|
|
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
571,000
|
|
|
516,000
|
|
|
890,000
|
|
|
736,000
|
|
|
Weighted average ceiling price ($/Bbl)(1)
|
|
$
|
60.19
|
|
|
$
|
60.20
|
|
|
$
|
60.14
|
|
|
$
|
60.16
|
|
|
Weighted average floor price ($/Bbl)(1)
|
|
$
|
45.00
|
|
|
$
|
45.00
|
|
|
$
|
45.00
|
|
|
$
|
45.00
|
|
|
(1)
The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude during the relevant period.
Derivative Fair Values and Gains (Losses)
The following table presents the fair value of derivative instruments. The Company’s derivatives are presented as separate line items in its consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussion related to the fair value of the Company’s derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
Liabilities
|
|
|
September 30, 2017
|
|
December 31, 2016
|
|
September 30, 2017
|
|
December 31, 2016
|
|
|
(In thousands)
|
Derivative Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
14,742
|
|
|
$
|
11,815
|
|
|
$
|
19,719
|
|
|
$
|
28,861
|
|
Noncurrent amounts
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
5,361
|
|
|
$
|
—
|
|
|
$
|
4,169
|
|
|
$
|
—
|
|
Total derivative instruments
|
|
$
|
20,103
|
|
|
$
|
11,815
|
|
|
$
|
23,888
|
|
|
$
|
28,861
|
|
Gains and losses on derivatives are reported in the consolidated statements of operations.
The following represents the Company’s reported gains (losses) on derivative instruments for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
(In thousands)
|
|
(In thousands)
|
Gain (loss) on derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
(21,626
|
)
|
|
$
|
(2,934
|
)
|
|
$
|
7,689
|
|
|
$
|
(6,222
|
)
|
Total
|
$
|
(21,626
|
)
|
|
$
|
(2,934
|
)
|
|
$
|
7,689
|
|
|
$
|
(6,222
|
)
|
Offsetting of Derivative Assets and Liabilities
The following table presents the Company’s gross and net derivative assets and liabilities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amount
Presented on
Balance Sheet
|
|
Netting
Adjustments(a)
|
|
Net Asset (Liability)
|
|
|
(In thousands)
|
September 30, 2017
|
|
|
|
|
|
|
|
|
|
Derivative instrument assets with right of offset or master netting agreements
|
|
$
|
20,103
|
|
|
$
|
(20,103
|
)
|
|
$
|
—
|
|
Derivative instrument liabilities with right of offset or master netting agreements
|
|
$
|
(23,888
|
)
|
|
$
|
20,103
|
|
|
$
|
(3,785
|
)
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
Derivative instrument assets with right of offset or master netting agreements
|
|
$
|
11,815
|
|
|
$
|
(11,815
|
)
|
|
$
|
—
|
|
Derivative instrument liabilities with right of offset or master netting agreements
|
|
$
|
(28,861
|
)
|
|
$
|
11,815
|
|
|
$
|
(17,046
|
)
|
(a)
The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
Credit-Risk Related Contingent Features in Derivatives
None of the Company’s derivative instruments contain credit-risk related contingent features.
No
amounts of collateral were posted by the Company related to net positions as of
September 30, 2017
and
December 31, 2016
.
NOTE 5—FAIR VALUE MEASUREMENTS
The book values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The book value of the Company’s revolving credit facility approximates fair value as the interest rate is variable. At
September 30, 2017
, the fair value of the Company's
6.625%
senior notes was
$733.3 million
and the fair value of the Company's
5.25%
senior notes was
$455.1 million
. If the Company recorded the
6.625%
senior notes at fair value they would be Level 1 in our fair value hierarchy as they are traded in an active market with quoted prices for identical instruments. If the Company recorded the
5.25%
senior notes at fair value they would be Level 2 in our fair value hierarchy as these notes have not been registered and do not trade in an active market as of
September 30, 2017
. The fair value of derivative financial instruments is determined utilizing 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.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
•
Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
•
Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
•
Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data and may reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Fair Value Measurement on a Recurring Basis
The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total fair value
|
|
|
(In thousands)
|
As of September 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
(3,785
|
)
|
|
$
|
—
|
|
|
$
|
(3,785
|
)
|
Total
|
|
$
|
—
|
|
|
$
|
(3,785
|
)
|
|
$
|
—
|
|
|
$
|
(3,785
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total fair value
|
|
|
(In thousands)
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
(17,046
|
)
|
|
$
|
—
|
|
|
$
|
(17,046
|
)
|
Total
|
|
$
|
—
|
|
|
$
|
(17,046
|
)
|
|
$
|
—
|
|
|
$
|
(17,046
|
)
|
Significant Level 2 assumptions used to measure the fair value of the commodity derivative instruments include implied volatility factors, appropriate risk adjusted discount rates, as well as other relevant data.
Reclassifications of fair value among Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers among Level 1, Level 2 or Level 3 during the
nine months ended September 30, 2017
and the year ended
December 31, 2016
.
Nonfinancial Assets and Liabilities
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement.
The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.
NOTE 6—LONG-TERM DEBT
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
December 31, 2016
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
Revolving credit facility
|
|
$
|
345,000
|
|
|
$
|
—
|
|
|
5.25% Senior notes
|
|
450,000
|
|
|
450,000
|
|
|
6.625% Senior notes
|
|
700,000
|
|
|
700,000
|
|
|
Less: Discount
|
|
(1,000
|
)
|
|
(1,150
|
)
|
|
Less: Debt issuance costs
|
|
(15,500
|
)
|
|
(16,575
|
)
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
1,478,500
|
|
|
$
|
1,132,275
|
|
|
Revolving Credit Facility
As of
September 30, 2017
, the borrowing base under the Company’s amended and restated credit agreement was
$1.1 billion
, with a Company-elected commitment of
$900 million
, and lender commitments of
$2.5 billion
. The maturity date of the Company’s revolving credit facility is December 19, 2021. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is redetermined semiannually each May and November and depends on the volumes of proved oil and natural gas reserves and estimated cash flows from these reserves and commodity hedge positions. As of
September 30, 2017
, we had
$345.0 million
in borrowings and
$0.4 million
of letters of credit outstanding under our revolving credit facility and
$554.6 million
of borrowing capacity.
On October 19, 2017, the Company entered into a first amendment to our credit agreement, which, (a) increased the borrowing base to
$1.5 billion
from
$1.1 billion
, (b) maintained our elected commitment at
$900 million
and (c) decreased the applicable margins for interest rates applicable to amounts outstanding under the revolving credit facility from a range of
200
to
300
basis points above the applicable reference rate for Eurodollar loans and
100
to
200
basis points above the applicable reference rate for alternate base rate loans to ranges of
150
to
250
basis points for Eurodollar loans and
50
to
150
basis points for alternate base rate loans.
The Company's revolving credit facility requires it to maintain the following
two
financial ratios:
•
a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its revolving credit facility and excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long-term debt under the credit facility and derivative liabilities), of not less than
1.0
to 1.0;
•
a leverage ratio, which is the ratio of the sum of all of the Company’s debt to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than
4.25
to 1.0.
The Company’s revolving credit facility also contains restrictive covenants that may limit its ability to, among other things, incur additional indebtedness, make loans to others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or its expected production, enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness, incur liens, sell assets or engage in certain other transactions without the prior consent of the lenders.
The Company was in compliance with such covenants and ratios as of
September 30, 2017
.
Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. The Company has a choice of borrowing at a Eurodollar rate or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the quotient of: (i) the LIBOR Rate; divided by (ii) a percentage equal to
100%
minus the maximum rate on such date at which the Administrative Agent is required to maintain reserves on “Eurocurrency Liabilities” as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from
200
to
300 basis points
, depending on the percentage of its borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s referenced rate; (ii) the federal funds effective rate plus
50 basis points
; and (iii) the adjusted LIBOR rate plus
100 basis points
, plus an applicable margin ranging from
100
to
200 basis points
, depending on the percentage of our borrowing base utilized, plus a commitment fee ranging from
37.5 basis points
to
50 basis points
charged on the undrawn commitment amount.
Senior Notes Due 2025
On December 27, 2016, the Company issued
$450.0 million
of
5.25%
senior unsecured notes at par through a private placement. The notes will mature on January 15, 2025. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are as a result of being unsecured effectively subordinated in rights to our assets constituting collateral held by all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including indebtedness under our revolving credit facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on these notes is payable semi-annually on January 15 and July 15, commencing on July 15, 2017. On or after January 15, 2020, the Company may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of
103.938%
of principal, declining in twelve-month intervals to
100%
in 2023 and thereafter. In addition, prior to January 15, 2020, on any one or more occasions, the Company may redeem all or part of the notes at a redemption price of
100%
of the principal amount of the notes redeemed, plus an applicable make-whole premium along with accrued and unpaid interest.
The Company incurred approximately
$6.4 million
of debt issuance costs related to the 2016 note issuance, which are a reduction to “Long-term debt” on the Company’s consolidated balance sheets and will be amortized to interest expense, net, over the life of the notes using the effective interest method. In the event of a change in control of the Company whereby the notes are downgraded, each note holder will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to
101%
of the principal amount, plus accrued and unpaid interest to the date of purchase. The notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. RSP Inc. does not have independent assets or operations. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. In November 2017, the Company exchanged
$450.0 million
of the
5.25%
senior unsecured notes for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the senior unsecured notes as of
September 30, 2017
.
Senior Notes Due 2022
On September 26, 2014, the Company issued
$500.0 million
of
6.625%
senior unsecured notes at par through a private placement. On August 10, 2015, the Company issued an additional
$200.0 million
of these notes at
99.25%
of the principal amount through a private placement. The notes will mature on October 1, 2022. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on these notes is payable semi-annually on April 1 and October 1. After October 1, 2017, the Company may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of
104.969%
of principal, declining in twelve-month intervals to
100%
in 2020 and thereafter.
The Company incurred approximately
$11.3 million
of debt issuance costs related to the 2014 note issuance and
$2.4 million
related to the 2015 note issuance, which are a reduction to “Long-term debt” on the Company’s consolidated balance sheets and will be amortized to interest expense, net, over the life of the notes using the effective interest method. In the event of certain changes in control of the Company, each note holder will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to
101%
of the principal amount, plus accrued and unpaid interest to the date of purchase. The notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. RSP Inc. does not have independent assets or operations. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. In June 2015, the Company exchanged
$500.0 million
of these notes for registered notes with the same terms. In March 2016, the Company exchanged an additional
$200.0 million
of these notes for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the senior unsecured notes as of
September 30, 2017
.
NOTE 7—COMMITMENTS AND CONTINGENCIES
Legal Matters
The Company is party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect, individually or in the aggregate, on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then-current status of the matters.
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. Environmental expenditures are expensed as incurred. 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.
The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both
September 30, 2017
and
December 31, 2016
, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Contractual Obligations
For the nine months ended
September 30, 2017
, the Company had no material changes in its contractual commitments and obligations from amounts listed under "Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements and Sources of Liquidity - Contractual Obligations” in our Annual Report on Form 10-K for the year ended
December 31, 2016
other than
$345.0 million
in borrowings under our revolving credit facility, compared to no outstanding borrowings at December 31, 2016.
NOTE 8—EQUITY-BASED COMPENSATION
Equity-based compensation expense, which was recorded in general and administrative expenses, was
$4.4 million
and
$3.3 million
for the
three months ended September 30, 2017
and
2016
, respectively. This equity-based compensation expense was
$12.7 million
and
$10.5 million
for the
nine months ended September 30, 2017
and
2016
, respectively.
Restricted Stock Awards
In connection with the Company's initial public offering, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company.
Equity-based compensation expense for awards under the LTIP was
$2.5 million
and
$1.9 million
for the
three months ended September 30, 2017
and
2016
, respectively. This equity-based compensation expense was
$7.5 million
and
$6.0 million
for the
nine months ended September 30, 2017
and
2016
, respectively.
The Company views restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life and amortize the awards on a straight-line basis over the life of the awards.
The compensation expense for these awards was determined based on the market price of the Company’s common stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of
September 30, 2017
, the Company had unrecognized compensation expense of
$15.5 million
related to restricted stock awards which is expected to be recognized over a weighted average period of
1.6
years.
The following table represents restricted stock award activity for the
nine months ended September 30
2017 and the twelve months ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
|
Shares
|
|
Weighted Average Fair Value
|
|
Shares
|
|
Weighted Average Fair Value
|
Restricted shares outstanding, beginning of period
|
|
656,895
|
|
|
$
|
22.21
|
|
|
499,529
|
|
|
$
|
25.99
|
|
Restricted shares granted
|
|
355,579
|
|
|
41.85
|
|
|
442,835
|
|
|
19.78
|
|
Restricted shares canceled
|
|
(24,109
|
)
|
|
31.76
|
|
|
(13,551
|
)
|
|
21.61
|
|
Restricted shares vested
|
|
(278,849
|
)
|
|
23.46
|
|
|
(271,918
|
)
|
|
25.22
|
|
Restricted shares outstanding, end of period
|
|
709,516
|
|
|
$
|
31.24
|
|
|
656,895
|
|
|
$
|
22.21
|
|
Performance-Based Restricted Stock Awards
In June 2014, performance-based restricted stock awards were granted containing predetermined market conditions with a cliff vesting period of
2.75 years
. We granted
134,400
of these shares at a
100%
of target payout while the conditions of the grants allow for a payout ranging between
no
payout and
200%
of target. In March 2015, an additional grant of performance-based restricted stock awards were granted containing predetermined market conditions with a cliff vesting period of
2.83 years
. We granted
159,932
of these shares at a
100%
of target payout while the conditions of the grants allow for a payout ranging between
no
payout and
200%
of target. In February 2016, an additional grant of performance-based restricted stock awards were granted containing predetermined market conditions with a cliff vesting period of
2.92 years
. We granted
484,650
of these shares at a
100%
of target payout while the conditions of the grants allow for a payout ranging from
no
payout and
100%
of target payout. In February 2017, an additional grant of performance-based restricted stock awards were granted
containing predetermined market conditions with a cliff vesting period of
2.92 years
. We granted
380,174
of these shares at a
100%
of target payout while the conditions of the grants allow for a payout ranging from
no
payout and
100%
of target payout.
Equity-based compensation for these awards was
$1.8 million
and
$1.3 million
for the
three months ended September 30, 2017
and
2016
, respectively. This equity-based compensation expense was
$5.2 million
and
$4.5 million
for the
nine months ended September 30, 2017
and
2016
, respectively.
The compensation expense for these performance based awards is based on a per share value using a Monte-Carlo simulation. The payout level is calculated based on actual total shareholder return performance achieved during the performance period compared to a defined peer group of comparable public companies. The unrecognized compensation expense related to these shares is approximately $
11.2
million as of
September 30, 2017
and is expected to be recognized over the next
1.5
years.
The following table represents performance-based restricted stock award activity for the
nine months ended September 30
2017 and the twelve months ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
|
Shares
|
|
Weighted Average Fair Value
|
|
Shares
|
|
Weighted Average Fair Value
|
Restricted shares outstanding, beginning of period
|
|
747,874
|
|
|
$
|
19.82
|
|
|
294,332
|
|
|
$
|
31.41
|
|
Restricted shares granted
|
|
380,174
|
|
|
26.96
|
|
|
484,650
|
|
|
13.53
|
|
Restricted shares canceled
|
|
(7,569
|
)
|
|
26.96
|
|
|
—
|
|
|
—
|
|
Restricted shares vested
|
|
(119,400
|
)
|
|
31.01
|
|
|
(31,108
|
)
|
|
31.39
|
|
Restricted shares outstanding, end of period
|
|
1,001,079
|
|
|
$
|
21.14
|
|
|
747,874
|
|
|
$
|
19.82
|
|
NOTE 9—EARNINGS PER SHARE
The Company’s basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of shares of common stock outstanding for the period. Because the Company recognized a net loss for the nine months ended September 30, 2016, all unvested restricted share awards were excluded from diluted earnings per share calculations for this period as they would be antidilutive. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(In thousands, except per share data)
|
Numerator:
|
|
|
|
|
|
Net income (loss) available to stockholders
|
|
$
|
21,326
|
|
|
$
|
985
|
|
Basic net income allocable to participating securities (1)
|
|
107
|
|
|
7
|
|
Income (loss) available to stockholders
|
|
$
|
21,219
|
|
|
$
|
978
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
Weighted average number of common shares outstanding - basic
|
|
156,864
|
|
|
100,234
|
|
Effect of dilutive securities:
|
|
|
|
|
|
Restricted stock
|
|
973
|
|
|
—
|
|
Weighted average number of common shares outstanding - diluted
|
|
157,837
|
|
|
100,234
|
|
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
Basic
|
|
$
|
0.14
|
|
|
$
|
0.01
|
|
Diluted
|
|
$
|
0.14
|
|
|
$
|
0.01
|
|
(1)
Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2017
|
|
2016
|
|
|
(In thousands, except per share data)
|
Numerator:
|
|
|
|
|
|
Net income (loss) available to stockholders
|
|
$
|
91,350
|
|
|
$
|
(26,234
|
)
|
Basic net income allocable to participating securities (1)
|
|
457
|
|
|
—
|
|
Income (loss) available to stockholders
|
|
$
|
90,893
|
|
|
$
|
(26,234
|
)
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
Weighted average number of common shares outstanding - basic
|
|
153,258
|
|
|
100,161
|
|
Effect of dilutive securities:
|
|
|
|
|
|
Restricted stock
|
|
1,020
|
|
|
—
|
|
Weighted average number of common shares outstanding - diluted
|
|
154,278
|
|
|
100,161
|
|
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
Basic
|
|
$
|
0.59
|
|
|
$
|
(0.26
|
)
|
Diluted
|
|
$
|
0.59
|
|
|
$
|
(0.26
|
)
|
(1)
Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.