Clayton Williams Energy, Inc. (the “Company”) (NYSE:CWEI) today
reported its financial results for the quarter and year ended
December 31, 2016.
Highlights
Fiscal 2016 Results
- Oil and Gas Production of 13.7
MBOE/d
- Cash flow from operating activities
of $10.7 million
- Liquidity of $671.1 million
Year-End 2016 Reserves
- Total Proved Reserves of 34.8
MMBOE
- 84% Oil and NGL and 63% Proved
Developed
Recent Transactions
- Announced Proposed Merger with Noble
Energy, Inc.
- Purchase of Net Mineral Acres in
Southern Reeves County, Texas
- Sale of Giddings Area assets for
$400 million
Financial Results for Fiscal Year 2016
The Company reported a net loss for fiscal 2016 of $292.2
million, or $20.87 per share, as compared to net loss of $98.2
million, or $8.07 per share, for fiscal 2015. Adjusted net loss1
(non-GAAP) for 2016 was $127.7 million, or $9.12 per share, as
compared to adjusted net loss1 (non-GAAP) of $70.4 million, or
$5.78 per share, for 2015. Cash flow from operations for 2016 was
$10.7 million as compared to $52.2 million for 2015. EBITDAX2
(non-GAAP) for 2016 was $54.6 million as compared to $112.1 million
for 2015.
The key factors affecting the comparability of the past two
years were:
- Oil and gas sales, excluding amortized
deferred revenues, decreased $54.1 million to $158.8 million in
2016 from $212.9 million in 2015. Production variances accounted
for $30.7 million of the decrease and price variances accounted for
$23.4 million of the decrease. Average realized oil prices were
$38.58 per barrel in 2016 versus $44.76 per barrel in 2015, average
realized gas prices were $2.31 per Mcf in 2016 versus $2.52 per Mcf
in 2015, and average realized natural gas liquids (“NGL”) prices
were $13.26 per barrel in 2016 versus $13.07 per barrel in 2015.
Amortized deferred revenue in 2016 totaled $1.5 million as compared
to $4.5 million in 2015.
- Oil, gas and NGL production per barrel
of oil equivalent per day (“BOE/d”) decreased 14% in 2016, to
13,652 BOE/d, as compared to 15,818 BOE/d in 2015, with oil
production decreasing 15% to 9,899 barrels per day, gas production
decreasing 16% to 13,369 Mcf per day, and NGL production increasing
1% to 1,525 barrels per day. Oil and NGL production accounted for
approximately 84% of the Company’s total BOE production in 2016
versus 83% in 2015. After giving effect to the sale of
substantially all of the Company’s assets in the Giddings Area in
East Central Texas in December 2016, the sale of interests in
certain wells in Glasscock County, Texas in July 2016 and the sale
of selected leases and wells in South Louisiana in September 2015,
oil, gas and NGL production per BOE/d increased 1% in 2016 as
compared to 2015. See accompanying tables for additional
information about the Company’s oil and gas production.
- Production costs in 2016 were $70.9
million versus $87.6 million in 2015 due to lower oilfield service
costs and decreased activity. After giving effect to a 14% decrease
in total production, production costs on a BOE basis, excluding
production taxes, decreased 4% to $12.68 per BOE in 2016 versus
$13.23 per BOE in 2015.
- Interest expense for 2016 was $93.7
million versus $54.4 million for 2015. The increase was due
primarily to $44.3 million of incremental interest expense on
funded indebtedness incurred under a second lien term loan credit
facility issued in connection with a refinancing in March 2016 (the
“Refinancing”). For the second and third quarters of 2016, the
Company elected to pay interest on the term loan facility in-kind
and resulted in an increase in the principal amount of the term
loan to $377.2 million.
- The Company accounts for the warrants
issued in connection with the Refinancing as derivative instruments
and carries the warrants as a non-current liability at their fair
value. The Company recorded a $230 million loss on change in fair
value in 2016 due primarily to the impact on the valuation model of
a 730% increase in the market price of the Company’s common stock
from $14.37 at March 15, 2016 to $119.26 at December 31, 2016.
- Loss on commodity derivatives for 2016
was $20.3 million (including a $7.4 million loss on settled
contracts) versus a gain on commodity derivatives in 2015 of $12.5
million (including a $12.5 million gain on settled contracts). See
accompanying tables for additional information about the Company’s
accounting for commodity derivatives.
- Lower commodity prices negatively
impacted our results of operations due to asset impairments. The
Company recorded impairments of property and equipment of $7.6
million in 2016, of which $5.2 million related primarily to
impairments of proved non-core properties located in North Dakota,
Oklahoma, California and the Cotton Valley area of Texas and $2.4
million related to the impairment of certain drilling rigs and
related equipment to reduce the carrying value to their estimated
fair values. By comparison, the Company recorded impairments of
property and equipment of $41.9 million in 2015, of which $37.9
million related primarily to impairments of proved non-core
properties in the Permian Basin and Oklahoma and $4 million related
to the impairment of certain drilling rigs and related equipment to
reduce the carrying value to their estimated fair values.
- The Company recorded a net gain of
$118.8 million on sales of assets and impairment of inventory in
2016 compared to a net loss of $3 million in 2015. The 2016 gain
related primarily to the sale of substantially all of the Company’s
assets in the Giddings Area in East Central Texas in December 2016
and the sale of interests in certain wells in Glasscock County,
Texas in July 2016. The 2015 loss related primarily to the
write-down of inventory to reduce the carrying value to the
estimated fair value offset by gains on the sale of selected leases
and wells in South Louisiana in September 2015, the release of
sales proceeds previously held in escrow pending resolution of
title requirements associated with the sale of certain non-core
Austin Chalk/Eagle Ford assets sold in March 2014, the sale of
leases in Oklahoma in May and June 2015, and the sale of selected
wells in Martin and Yoakum Counties, Texas in March 2015.
- The Company recorded an $8.4 million
charge to fully impair the carrying value of the Company’s
investment in Dalea Investment Group, LLC in 2016, as compared to a
partial impairment of this investment of $2.6 million in 2015.
- General and administrative (“G&A”)
expenses for 2016 were $23 million versus $22.8 million for 2015.
G&A expense increased due primarily to increases in salary and
personnel expense. Changes in compensation expense related to the
Company’s APO Reward Plans accounted for a $7.9 million decrease
($7.9 million credit in 2016 versus a negligible credit in 2015)
which was due primarily to reductions in previously accrued
compensation associated with the APO Reward Plans affected by the
Giddings sale. Compensation expense related to issuances of
restricted stock and stock options under the Company’s long-term
incentive plan (“LTIP”) accounted for a $5.7 million increase.
- The Company redeemed $100 million of
7.75% Senior Notes due 2019 (“2019 Senior Notes”) in a tender offer
in August 2016 and recorded a gain on early extinguishment of
long-term debt during 2016 of $4 million.
Financial Results for the Fourth Quarter of 2016
The Company reported net loss for the fourth quarter of 2016
(“4Q16”) of $27.2 million, or $1.54 per share, as compared to a net
loss of $47.2 million, or $3.88 per share, for the fourth quarter
of 2015 (“4Q15”). Adjusted net loss1 (non-GAAP) for 4Q16 was $26.2
million, or $1.49 per share, as compared to adjusted net loss1
(non-GAAP) of $22.1 million, or $1.82 per share, for 4Q15. Cash
flow from operations for 4Q16 was $2.8 million as compared to
$(2.8) million for 4Q15. EBITDAX2 (non-GAAP) for 4Q16 was $13.3
million as compared to $20.7 million for 4Q15.
The key factors affecting the comparability of financial results
for 4Q16 versus 4Q15 were:
- Oil and gas sales for 4Q16, excluding
amortized deferred revenues, increased $7.9 million to $46.6
million in 4Q16 from $38.7 million in 4Q15. Price variances
accounted for $8.5 million of the increase and production variances
accounted for $0.6 million of the decrease. Average realized oil
prices were $44.87 per barrel in 4Q16 versus $36.91 per barrel in
4Q15, average realized gas prices were $2.70 per Mcf in 4Q16 versus
$2.09 per Mcf in 4Q15, and average realized NGL prices were $16.72
per barrel in 4Q16 versus $13.00 per barrel in 4Q15. Amortized
deferred revenue in 4Q16 totaled $0.4 million as compared to $0.3
million in 4Q15.
- Oil, gas and NGL production per BOE/d
decreased 4% in 4Q16 to 13,441 BOE/d as compared to 13,939 BOE/d in
4Q15, with oil production decreasing 1% to 9,957 barrels per day,
gas production decreasing 15% to 12,359 Mcf per day, and NGL
production decreasing 1% to 1,424 barrels per day. Oil and NGL
production accounted for approximately 85% of the Company’s total
BOE production in 4Q16 versus 83% in 4Q15. After giving effect to
the sale of substantially all of the Company’s assets in the
Giddings Area in East Central Texas in December 2016 and the sale
of interests in certain wells in Glasscock County, Texas in July
2016, oil, gas and NGL production per BOE/d increased 11% in 4Q16
as compared to 4Q15. See accompanying tables for additional
information about the Company’s oil and gas production.
- Production costs in 4Q16 were $16.8
million versus $20.4 million in 4Q15 due to lower oilfield service
costs and decreased activity. Production costs on a BOE basis,
excluding production taxes, decreased 17% to $11.71 per BOE in 4Q16
versus $14.07 per BOE in 4Q15.
- Interest expense for 4Q16 was $23.5
million versus $14 million for 4Q15. The increase was due primarily
to $13.1 million of incremental interest expense on funded
indebtedness incurred under a second lien term loan credit facility
issued in connection with the Refinancing.
- The Company accounts for the warrants
issued in connection with the Refinancing as derivative instruments
and carries the warrants as a non-current liability at their fair
value. The Company recorded a $75 million loss on change in fair
value in 4Q16 due primarily to the impact on the valuation model of
a 40% increase in the market price of the Company’s common stock
from $85.44 at September 30, 2016 to $119.26 at December 31,
2016.
- Loss on commodity derivatives for 4Q16
was $6.3 million (including a $5 million loss on settled contracts)
versus a gain on commodity derivatives in 4Q15 of $2.1 million
(including a $7.9 million gain on settled contracts). See
accompanying tables for additional information about the Company’s
accounting for commodity derivatives.
- Lower commodity prices negatively
impacted our results of operations due to asset impairments. The
Company recorded impairments of property and equipment of $4.2
million in 4Q16, of which $1.8 million related primarily to
impairments of proved non-core properties in North Dakota and $2.4
million related to the impairment of certain drilling rigs and
related equipment to reduce the carrying value to their estimated
fair values. By comparison, the Company recorded impairments of
property and equipment of $36.3 million in 4Q15, of which $32.3
million related primarily to impairments of proved non-core
properties in the Permian Basin and Oklahoma and $4 million related
to the impairment of certain drilling rigs and related equipment to
reduce the carrying value to their estimated fair values.
- The Company recorded a net gain of
$110.8 million on sales of assets and impairment of inventory in
4Q16 compared to a net loss of $3.9 million in 4Q15. The 4Q16 gain
related primarily to the sale of substantially all of the Company’s
assets in the Giddings Area in East Central Texas in December 2016
and the 4Q15 loss related primarily to the write-down of inventory
to reduce the carrying value to the estimated fair value.
- G&A expenses were negligible for
4Q16 versus a $2.3 million credit for 4Q15. G&A expense
increased due primarily to increases in salary and personnel
expense. Changes in compensation expense related to the Company’s
APO Reward Plans accounted for a decrease of $8.5 million ($15.2
million credit in 4Q16 versus a $6.7 million credit in 4Q15) which
was due primarily to reductions in previously accrued compensation
associated with the APO Reward Plans affected by the Giddings sale.
Compensation expense related to issuances of restricted stock and
stock options under the Company’s LTIP accounted for a $4.9 million
increase.
1 See “Computation of Adjusted Net Loss (non-GAAP)” below
for an explanation of how the Company calculates and uses adjusted
net loss (non-GAAP) and for a reconciliation of net loss (GAAP) to
adjusted net loss (non-GAAP). 2 See “Computation of EBITDAX
(non-GAAP)” below for an explanation of how the Company calculates
and uses EBITDAX (non-GAAP) and for a reconciliation of net loss
(GAAP) to EBITDAX (non-GAAP).
Balance Sheet and Liquidity
As of December 31, 2016, total long-term debt was $848
million, consisting of $352.5 million (net of $24.7 million of
original issue discount and debt issuance costs) under the second
lien term loan credit facility and $495.5 million (net of $4.5
million of original issue discount and debt issuance costs) of 2019
Senior Notes. The borrowing base established by the banks under the
revolving credit facility and the aggregate lender commitment was
$100 million at December 31, 2016. The Company had $98.1
million of availability under the revolving credit facility after
allowing for outstanding letters of credit of $1.9 million.
Liquidity, consisting of cash and funds available on the revolving
credit facility, totaled $671.1 million.
Subsequent Events
Proposed Merger with Noble Energy, Inc.
On January 16, 2017, the Company and Noble Energy, Inc. (“Noble
Energy”) announced that the Boards of Directors of both companies
unanimously approved and executed a definitive agreement under
which Noble Energy will acquire all of the outstanding common stock
of the Company for $2.7 billion in Noble Energy common stock and
cash. The merger is expected to close in the second quarter of
2017.
Purchase of Net Mineral Acres in Southern Reeves County,
Texas
In January 2017, the Company purchased approximately 1,900 net
mineral acres in Southern Reeves County, Texas from a private
seller, for cash consideration totaling $44.3 million. The acreage
is located in and around the Company’s existing contiguous acreage
block. Also included in the deal was a non-operated gross working
interest of approximately 26% in an existing horizontal well.
Reserves
The Company reported total estimated proved oil and gas reserves
as of December 31, 2016 of 34.8 million barrels of oil
equivalent (“MMBOE”), consisting of 24.3 million barrels of oil,
4.8 million barrels of NGL and 33.6 Bcf of natural gas. On a BOE
basis, oil and NGL comprised 84% of total proved reserves at
year-end 2016 versus 83% at year-end 2015. Proved developed
reserves at year-end 2016 were 22 MMBOE, or 63% of total proved
reserves, versus 36.3 MMBOE, or 78% of total proved reserves, at
year-end 2015. The present value of estimated future net cash flows
from total proved reserves, before deductions for estimated future
income taxes and asset retirement obligations, discounted at 10%
(referred to as “PV-10”), totaled $204.4 million at year-end 2016
versus $442.8 million at year-end 2015. See accompanying tables for
a reconciliation of PV-10 (a non-GAAP financial measure) to
standardized measure of discounted future net cash flows (a GAAP
financial measure).
The following table summarizes the changes in total proved
reserves during 2016 on an MMBOE basis:
MMBOE Total proved reserves, December
31, 2015 46.6 Extensions and discoveries 4.1 Revisions (0.2 ) Sales
of reserves (10.7 ) Production (5.0 ) Total proved reserves,
December 31, 2016 34.8
The Company replaced 82% of its 2016 oil and gas production
through extensions and discoveries. Most of the 4.1 MMBOE of
reserve additions in 2016 are attributable to the Company’s
Delaware Basin program in Southern Reeves County, Texas. Oil and
NGL accounted for 85.1% of the 2016 reserve additions.
The 0.2 MMBOE of net downward revisions in proved reserves
resulted from a combination of (1) net upward revisions of 11.6
MMBOE related to performance in the Company’s Delaware Basin
reserves in Southern Reeves County, Texas, and (2) downward
revisions of 11.8 MMBOE related to the effects of lower commodity
prices on the estimated quantities of proved reserves.
SEC guidelines require that the Company’s estimated proved
reserves and related PV-10 be determined using benchmark commodity
prices equal to the unweighted arithmetic average of the
first-day-of-the-month prices for the 12-month period prior to the
effective date of each reserve estimate. The benchmark averages for
2016 were $42.75 per barrel of oil and $2.49 per MMBtu of natural
gas, as compared to $50.28 per barrel of oil and $2.58 per MMBtu of
natural gas for 2015. These benchmark prices were further adjusted
for quality, energy content, transportation fees and other price
differentials specific to the Company’s properties, resulting in an
average adjusted price over the remaining life of the proved
reserves of $36.60 per barrel of oil, $13.60 per barrel of NGL and
$2.36 per Mcf of natural gas for year-end 2016, as compared to
$45.75 per barrel of oil, $15.84 per barrel of NGL and $2.52 per
Mcf of natural gas for year-end 2015.
Clayton Williams Energy, Inc. is an independent energy company
located in Midland, Texas.
This release contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. All statements, other
than statements of historical or current facts, that address
activities, events, outcomes and other matters that we plan,
expect, intend, assume, believe, budget, predict, forecast,
project, estimate or anticipate (and other similar expressions)
will, should or may occur in the future are forward-looking
statements. These forward-looking statements are based on
management's current belief, based on currently available
information, as to the outcome and timing of future events. The
Company cautions that its future natural gas and liquids
production, revenues, cash flows, liquidity, plans for future
operations, expenses, outlook for oil and natural gas prices,
timing of capital expenditures and other forward-looking statements
are subject to all of the risks and uncertainties, many of which
are beyond our control, incident to the exploration for and
development, production and marketing of oil and gas.
These risks include, but are not limited to, the possibility of
unsuccessful exploration and development drilling activities, our
ability to replace and sustain production, commodity price
volatility, domestic and worldwide economic conditions, the
availability of capital on economic terms to fund our capital
expenditures and acquisitions, our level of indebtedness, the
impact of the current economic recession on our business
operations, financial condition and ability to raise capital,
declines in the value of our oil and gas properties resulting in a
decrease in our borrowing base under our credit facility and
impairments, the ability of financial counterparties to perform or
fulfill their obligations under existing agreements, the
uncertainty inherent in estimating proved oil and gas reserves and
in projecting future rates of production and timing of development
expenditures, drilling and other operating risks, lack of
availability of goods and services, regulatory and environmental
risks associated with drilling and production activities, the
adverse effects of changes in applicable tax, environmental and
other regulatory legislation, and other risks and uncertainties are
described in the Company's filings with the Securities and Exchange
Commission. The Company undertakes no obligation to publicly update
or revise any forward-looking statements.
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED
STATEMENTS OF OPERATIONS (Unaudited) (In thousands,
except per share)
Three Months EndedDecember
31,
Year EndedDecember 31,
2016 2015 2016
2015 REVENUES Oil and gas sales $ 46,980 $ 38,946 $ 160,331
$ 217,485 Midstream services 1,791 1,408 5,688 6,122 Drilling rig
services — — — 23 Other operating revenues 112,693
64 123,392 8,742 Total
revenues 161,464 40,418 289,411
232,372 COSTS AND EXPENSES Production
16,760 20,369 70,920 87,557 Exploration: Abandonments and
impairments 29 1,504 3,536 6,509 Seismic and other 504 108 925
1,318 Midstream services 809 349 2,173 1,688 Drilling rig services
347 820 3,938 5,238 Depreciation, depletion and amortization 30,474
40,626 145,614 162,262 Impairment of property and equipment 4,155
36,297 7,593 41,917 Accretion of asset retirement obligations 1,004
1,009 4,364 3,945 General and administrative (39 ) (2,314 ) 22,988
22,788 Other operating expenses 1,952 4,106
5,046 12,585 Total costs and
expenses 55,995 102,874 267,097
345,807 Operating income (loss) 105,469
(62,456 ) 22,314 (113,435 )
OTHER INCOME (EXPENSE) Interest expense (23,469 ) (13,971 )
(93,693 ) (54,422 ) Gain on early extinguishment of long-term debt
— — 3,967 — Loss on change in fair value of common stock warrants
(75,024 ) — (229,980 ) — Gain (loss) on commodity derivatives
(6,292 ) 2,088 (20,289 ) 12,519 Impairment of investment and other
1,035 (304 ) (4,797 ) 2,003
Total other income (expense) (103,750 )
(12,187 ) (344,792 ) (39,900 ) Income (loss) before
income taxes 1,719 (74,643 ) (322,478 ) (153,335 ) Income tax
(expense) benefit (28,896 ) 27,434
30,327 55,139 NET LOSS $ (27,177 ) $ (47,209 )
$ (292,151 ) $ (98,196 ) Net loss per common share: Basic $
(1.54 ) $ (3.88 ) $ (20.87 ) $ (8.07 ) Diluted $ (1.54 ) $ (3.88 )
$ (20.87 ) $ (8.07 ) Weighted average common shares outstanding:
Basic 17,608 12,170 14,000
12,170 Diluted 17,608
12,170 14,000 12,170
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE
SHEETS (In thousands) ASSETS
December 31, December 31, 2016
2015 CURRENT ASSETS
(Unaudited) Cash and cash
equivalents $ 573,025 $ 7,780 Accounts receivable: Oil and gas
sales 18,752 16,660 Joint interest and other, net 4,148 3,661
Affiliates 258 260 Inventory 25,781 31,455 Deferred income taxes
6,520 6,526 Prepaids and other 2,702 2,463
631,186 68,805 PROPERTY AND
EQUIPMENT Oil and gas properties, successful efforts method
1,717,209 2,585,502 Pipelines and other midstream facilities 63,228
60,120 Contract drilling equipment 118,256 123,876 Other
20,822 19,371 1,919,515 2,788,869 Less
accumulated depreciation, depletion and amortization
(1,063,379 ) (1,587,585 ) Property and equipment, net
856,136 1,201,284 OTHER ASSETS
Investments and other 7,317 17,331 $
1,494,639 $ 1,287,420
LIABILITIES AND
SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable:
Trade $ 44,809 $ 29,197 Oil and gas sales 20,862 19,490 Affiliates
252 383 Fair value of commodity derivatives 12,895 — Accrued
liabilities and other 27,948 16,669
106,766 65,739 NON-CURRENT LIABILITIES
Long-term debt 847,995 742,410 Fair value of common stock warrants
246,743 — Deferred income taxes 76,590 108,996 Asset retirement
obligations 47,223 48,728 Accrued compensation under non-equity
award plans 4,655 16,254 Deferred revenue from volumetric
production payment and other 4,136 5,695
1,227,342 922,083 SHAREHOLDERS’
EQUITY Preferred stock, par value $.10 per share — — Common stock,
par value $.10 per share 1,763 1,216 Additional paid-in capital
305,223 152,686 Retained earnings (accumulated deficit)
(146,455 ) 145,696 Total shareholders' equity
160,531 299,598 $ 1,494,639 $ 1,287,420
CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (In thousands)
Three Months EndedDecember
31,
Year EndedDecember 31,
2016 2015 2016
2015 CASH FLOWS FROM OPERATING ACTIVITIES Net loss $ (27,177
) $ (47,209 ) $ (292,151 ) $ (98,196 ) Adjustments to reconcile net
loss to cash provided by (used in) operating activities:
Depreciation, depletion and amortization 30,474 40,626 145,614
162,262 Impairment of property and equipment 4,155 36,297 7,593
41,917 Abandonments and impairments 29 1,504 3,536 6,509 (Gain)
loss on sales of assets and impairment of inventory, net (110,848 )
3,853 (118,786 ) 3,018 Deferred income tax expense (benefit) 26,823
(27,513 ) (32,400 ) (55,218 ) Non-cash employee compensation
(13,264 ) (7,079 ) (6,019 ) (2,674 ) (Gain) loss on commodity
derivatives 6,292 (2,088 ) 20,289 (12,519 ) Cash settlements of
commodity derivatives (5,023 ) 7,934 (7,394 ) 12,519 Loss on change
in fair value of common stock warrants 75,024 — 229,980 — Accretion
of asset retirement obligations 1,004 1,009 4,364 3,945
Amortization of debt issue costs and original issue discount 1,589
1,005 7,106 3,246 Gain on early extinguishment of long-term debt —
— (3,967 ) — Paid in-kind interest expense — — 27,196 —
Amortization of deferred revenue from volumetric production payment
(413 ) (1,641 ) (1,479 ) (6,822 ) Impairment of investment and
other 221 873 8,751 1,542 Changes in operating working capital:
Accounts receivable (1,679 ) 5,510 (2,577 ) 30,817 Accounts payable
12,359 (3,803 ) 10,657 (35,860 ) Other 3,195
(12,115 ) 10,414 (2,327 ) Net cash provided by
(used in) operating activities 2,761 (2,837 )
10,727 52,159 CASH FLOWS FROM INVESTING
ACTIVITIES Additions to property and equipment (49,210 ) (24,147 )
(111,541 ) (179,827 ) Termination of volumetric production payment
— — — (13,703 ) Net redemption of short-term investments 40,041 — —
— Proceeds from sales of assets 396,536 23,976 423,905 71,460
(Increase) decrease in equipment inventory (138 ) 603 1,414 1,733
Proceeds from volumetric production payment and other 138
1,443 (551 ) 2,942 Net
cash provided by (used in) investing activities 387,367
1,875 313,227 (117,395 )
CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt —
— 343,237 45,000 Net repayments of Senior Notes — — (95,001 ) —
Repayments of long-term debt — — (160,000 ) — Payment of debt
issuance costs (90 ) — (11,048 ) — Proceeds from sale of common
stock (6 ) — 147,340 — Proceeds from issuance of common stock
warrants — — 16,763
— Net cash provided by (used in) financing activities
(96 ) — 241,291 45,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 390,032
(962 ) 565,245 (20,236 ) CASH AND CASH EQUIVALENTS Beginning of
period 182,993 8,742 7,780
28,016 End of period $ 573,025 $ 7,780
$ 573,025 $ 7,780
CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF ADJUSTED NET LOSS
(NON-GAAP)
(Unaudited)
(In thousands, except per
share)
Adjusted net loss is presented as a supplemental non-GAAP
financial measure because of its wide acceptance by financial
analysts, investors, debt holders, banks, rating agencies and other
financial statement users as a tool for operating trends analysis
and industry comparisons. Adjusted net loss is not an alternative
to net loss presented in conformity with GAAP.
The Company defines adjusted net loss as net loss before changes
in fair value of commodity derivatives and common stock warrants,
abandonments and impairments, impairments of property and
equipment, net (gain) loss on sales of assets and impairment of
inventory, gain on early extinguishment of long-term debt,
amortization of deferred revenue from volumetric production
payment, impairment of investments, certain non-cash and unusual
items and the impact on taxes of the adjustments for each period
presented.
The following table is a reconciliation of net loss (GAAP) to
adjusted net loss (non-GAAP):
Three
Months Ended Year Ended December 31, December
31, 2016 2015 2016 2015 Net
loss $ (27,177 ) $ (47,209 ) $ (292,151 ) $ (98,196 ) (Gain)
loss on commodity derivatives 6,292 (2,088 ) 20,289 (12,519 ) Cash
settlements of commodity derivatives (5,023 ) 7,934 (7,394 ) 12,519
Loss on change in fair value of common stock warrants 75,024 —
229,980 — Abandonments and impairments 29 1,504 3,536 6,509
Impairment of property and equipment 4,155 36,297 7,593 41,917 Net
(gain) loss on sales of assets and impairment of inventory (110,848
) 3,853 (118,786 ) 3,018 Gain on early extinguishment of long-term
debt — — (3,967 ) — Amortization of deferred revenue from
volumetric production payment (413 ) (1,641 ) (1,479 ) (6,822 )
Non-cash employee compensation (13,264 ) (7,079 ) (6,019 ) (2,674 )
Impairment of investment and other 221 873 8,751 1,542 Tax impact
(a) 44,807 (14,592 ) 31,972
(15,656 )
Adjusted net loss $ (26,197 ) $ (22,148 ) $
(127,675 ) $ (70,362 )
Adjusted earnings per share:
Diluted $ (1.49 ) $ (1.82 ) $ (9.12 ) $ (5.78 )
Weighted
average common shares outstanding: Diluted 17,608 12,170 14,000
12,170
Effective tax rates 37.7 % 36.8 % 32.8 % 36.0
%
______
(a) The tax impact is computed utilizing the Company’s
effective tax rate on the adjustments for each period presented,
giving effect to the loss on change in fair value of common stock
warrants being non-deductible for income tax purposes.
CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF EBITDAX
(NON-GAAP)
(Unaudited)
(In thousands)
EBITDAX is presented as a supplemental non-GAAP financial
measure because of its wide acceptance by financial analysts,
investors, debt holders, banks, rating agencies and other financial
statement users as an indication of an entity's ability to meet its
debt service obligations and to internally fund its exploration and
development activities. EBITDAX is not an alternative to net loss
or cash flow from operating activities, or any other measure of
financial performance presented in conformity with GAAP.
The Company defines EBITDAX as net loss before interest expense,
income taxes, exploration costs, net (gain) loss on sales of assets
and impairment of inventory, gain on early extinguishment of
long-term debt and all non-cash items in the Company's statements
of operations, including depreciation, depletion and amortization,
impairment of property and equipment, accretion of asset retirement
obligations, amortization of deferred revenue from volumetric
production payment, certain employee compensation, changes in fair
value of commodity derivatives and common stock warrants,
impairment of investments and certain non-cash and unusual
items.
The following table reconciles net loss to EBITDAX:
Three
Months Ended Year Ended December 31, December
31, 2016 2015 2016 2015 Net loss $
(27,177 ) $ (47,209 ) $ (292,151 ) $ (98,196 ) Interest expense
23,469 13,971 93,693 54,422 Income tax expense (benefit) 28,896
(27,434 ) (30,327 ) (55,139 ) Exploration: Abandonments and
impairments 29 1,504 3,536 6,509 Seismic and other 504 108 925
1,318 Net (gain) loss on sales of assets and impairment of
inventory (110,848 ) 3,853 (118,786 ) 3,018 Gain on early
extinguishment of long-term debt — — (3,967 ) — Depreciation,
depletion and amortization 30,474 40,626 145,614 162,262 Impairment
of property and equipment 4,155 36,297 7,593 41,917 Accretion of
asset retirement obligations 1,004 1,009 4,364 3,945 Amortization
of deferred revenue from volumetric production payment (413 )
(1,641 ) (1,479 ) (6,822 ) Non-cash employee compensation (13,264 )
(7,079 ) (6,019 ) (2,674 ) (Gain) loss on commodity derivatives
6,292 (2,088 ) 20,289 (12,519 ) Cash settlements of commodity
derivatives (5,023 ) 7,934 (7,394 ) 12,519 Loss on change in fair
value of common stock warrants 75,024 — 229,980 — Impairment of
investment and other 221 873
8,751 1,542 EBITDAX (a) $ 13,343 $
20,724 $ 54,622 $ 112,102
The
following table reconciles net cash provided by (used in) operating
activities to EBITDAX: Net cash provided by (used in)
operating activities $ 2,761 $ (2,837 ) $ 10,727 $ 52,159 Changes
in operating working capital (13,875 ) 10,408 (18,494 ) 7,370
Seismic and other 504 108 925 1,318 Current income tax provision
2,073 79 2,073 79 Cash interest expense 21,880
12,966 59,391 51,176 EBITDAX (a)
$ 13,343 $ 20,724 $ 54,622 $ 112,102
______
(a) In December 2016, the Company sold substantially all of
its assets in the Giddings Area in East Central Texas. Revenue, net
of direct expenses, associated with the sold properties was $8.1
million during the three months ended December 31, 2016, $8.7
million during the three months ended December 31 2015, $30.3
million for the year ended December 31, 2016 and $66.2 million for
the year ended December 31, 2015.
CLAYTON WILLIAMS ENERGY, INC. SUMMARY PRODUCTION
AND PRICE DATA (Unaudited)
Three Months EndedDecember
31,
Year EndedDecember 31,
2016 2015 2016
2015 Oil and Gas Production Data: Oil (MBbls) 916 927
3,623 4,257 Gas (MMcf) 1,137 1,340 4,893 5,798 Natural gas liquids
(MBbls) 131 132 558 550 Total (MBOE)(a) 1,237 1,282 4,997 5,773
Total (BOE/d) 13,441 13,939 13,652 15,818
Average Realized
Prices (b) (c): Oil ($/Bbl) $ 44.87 $
36.91 $ 38.58 $ 44.76 Gas ($/Mcf) $ 2.70 $ 2.09 $
2.31 $ 2.52 Natural gas liquids ($/Bbl) $ 16.72 $
13.00 $ 13.26 $ 13.07
Gain (Loss) on Settled Commodity
Derivative Contracts (c): ($ in thousands, except
per unit) Oil: Cash settlements received (paid) $ (5,023 ) $ 7,934
$ (7,394 ) $ 12,519 Per unit produced ($/Bbl) $ (5.48 ) $ 8.56 $
(2.04 ) $ 2.94
Average Daily Production (d):
Oil (Bbls): Permian Basin Area: Delaware Basin 4,091 3,026 3,395
3,426 Other 2,651 2,762 2,808 2,882 Austin Chalk 1,594 1,663 1,677
1,828 Eagle Ford Shale 1,365 2,347 1,632 3,037 Other 256
278 387 490 Total 9,957
10,076 9,899 11,663 Natural Gas
(Mcf): Permian Basin Area: Delaware Basin 2,482 3,206 2,629 3,078
Other 5,551 5,648 5,689 5,873 Austin Chalk 1,724 1,687 1,706 1,725
Eagle Ford Shale 273 444 322 516 Other 2,329
3,580 3,023 4,693 Total 12,359
14,565 13,369 15,885 Natural Gas
Liquids (Bbls): Permian Basin Area: Delaware Basin 367 386 435 409
Other 715 742 750 770 Austin Chalk 175 162 182 168 Eagle Ford Shale
66 113 80 123 Other 101 32 78
37 Total 1,424 1,435 1,525
1,507 BOE/d: Permian Basin Area: Delaware Basin 4,872
3,946 4,268 4,348 Other (e) 4,291 4,446 4,506 4,631 Austin Chalk
(f) 2,056 2,106 2,143 2,284 Eagle Ford Shale(f) 1,477 2,534 1,766
3,246 Other (g) 745 907 969
1,309 Total 13,441 13,939 13,652
15,818
Oil and Gas Costs ($/BOE
Produced): Production costs $ 13.55 $ 15.89 $ 14.19 $ 15.17
Production costs (excluding production taxes) $ 11.71 $ 14.07 $
12.68 $ 13.23 Oil and gas depletion $ 21.89 $ 28.83 $ 26.21 $ 25.54
______
(a) Natural gas reserves have been converted to oil
equivalents at the ratio of six Mcf of gas to one Bbl of oil.
(b) Oil and gas sales includes $0.4 million for three months
ended December 31, 2016, $0.3 million for the three months ended
December 31, 2015, $1.5 million for the year ended December 31,
2016 and $4.5 million for the year ended December 31, 2015 of
amortized deferred revenue attributable to a volumetric production
payment (“VPP”) transaction effective March 1, 2012. In August
2015, we terminated the VPP covering 277 MBOE of oil and gas
production from August 2015 through December 2019 for $13.7
million. The calculation of average realized sales prices excludes
production of 53,026 barrels of oil and 35,735 Mcf of gas for the
year ended December 31, 2015 associated with the VPP. (c) No
commodity derivatives were designated as cash flow hedges in the
table above. All gains or losses on settled commodity derivatives
were included in other income (expense) - gain (loss) on commodity
derivatives. (d) Historical average daily production volumes
have been reclassified to conform with current period presentation.
(e) The average daily production related to interests in
certain wells in Glasscock County, Texas sold in July 2016 was none
for the three months ended December 31, 2016, 57 total BOE/d for
the three months ended December 31, 2015, 49 total BOE/d for the
year ended December 31, 2016 and 104 total BOE/d for the year ended
December 31, 2015. (f) The average daily production related
to assets in the Giddings Area in East Central Texas sold in
December 2016 was 3,681 total BOE/d for the three months ended
December 31, 2016, 5,104 total BOE/d for the three months ended
December 31, 2015, 4,145 total BOE/d for the year ended December
31, 2016 and 5,977 total BOE/d for the year ended December 31,
2015. (g) The average daily production related to selected
leases and wells in South Louisiana sold in September 2015 was 390
total BOE/d for the year ended December 31, 2015.
CLAYTON WILLIAMS ENERGY, INC.
SUMMARY OF OPEN COMMODITY
DERIVATIVES
(Unaudited)
The following summarizes information concerning the Company’s
net positions in open commodity derivatives applicable to periods
subsequent to December 31, 2016. Settlement prices of commodity
derivatives are based on NYMEX futures prices.
Swaps:
Oil MBbls Price
Production Period: 1st Quarter 2017 178 $ 44.85 2nd Quarter 2017
165 $ 44.65 3rd Quarter 2017 37 $ 50.00 4th Quarter 2017 27 $ 50.00
407
Costless Collars:
Oil Weighted
Weighted Average Average MBbls Floor
Price Ceiling Price Production Period: 1st Quarter 2017
355 $ 42.26 $ 51.67 2nd Quarter 2017 354 $ 42.27 $ 51.67 3rd
Quarter 2017 356 $ 42.27 $ 51.65 4th Quarter 2017 350 $ 42.27 $
51.66 1,415
CLAYTON WILLIAMS ENERGY, INC.
PROVED RESERVES
(Unaudited)
The following table sets forth the Company’s estimated
quantities of proved reserves as of December 31, 2016 and
2015, all of which are located in the United States.
Proved Reserves Reserve Category
Oil(MBbls)
Natural GasLiquids
(MBbls)
Natural Gas(MMcf)
Total OilEquivalents
(a)(MBOE)
December 31, 2016 Developed 14,540 3,335 24,620 21,978
Undeveloped 9,807 1,476 8,957 12,776 Total Proved 24,347 4,811
33,577 34,754
December 31, 2015 Developed 25,349 4,266
39,987 36,280 Undeveloped 7,727 1,202 8,160 10,289 Total Proved
33,076 5,468 48,147 46,569 ______ (a) Natural gas reserves
have been converted to oil equivalents at the rate of six Mcf to
one barrel of oil.
PV-10 totaled $204.4 million at December 31, 2016 versus
$442.8 million at December 31, 2015. Commodity prices used at
December 31, 2016 and 2015 were based on the 12-month weighted
average of the first-day-of-the-month prices from January through
December of the respective years and averaged $42.75 per barrel of
oil and $2.49 per MMBtu of natural gas for 2016 and $50.28 per
barrel of oil and $2.58 per MMBtu for 2015. These benchmark prices
were further adjusted for quality, energy content, transportation
fees and other price differentials specific to the Company’s
properties, resulting in average adjusted commodity prices of
$36.60 per barrel of oil, $13.60 per barrel of NGL and $2.36 per
Mcf of natural gas for 2016 and $45.75 per barrel of oil, $15.84
per barrel of NGL and $2.52 per Mcf of natural gas for 2015.
PV-10 is a non-GAAP financial measure that the Company believes
is useful as a supplemental disclosure to the standardized measure
of discounted future net cash flows, a GAAP financial measure.
While the standardized measure of discounted future net cash flows
is dependent on the unique tax situation of each entity, PV-10 is
based on prices and discount factors that are consistent for all
entities and can be used within the industry and by securities
analysts to evaluate proved reserves on a more comparable basis.
The following table reconciles PV-10 to the standardized measure of
discounted future net cash flows.
As of December 31, 2016
2015 (In thousands) PV-10, a non-GAAP financial
measure $ 204,385 $ 442,775 Less present value, discounted at 10%
of: Estimated asset retirement obligations (37,764 ) (35,406 )
Estimated future income taxes (7,658 ) (16,726 )
Standardized measure of discounted future net cash flows, a GAAP
financial measure $ 158,963 $ 390,643
View source
version on businesswire.com: http://www.businesswire.com/news/home/20170302006463/en/
Clayton Williams Energy, Inc.Patti Hollums,
432-688-3419Director of Investor
Relationscwei@claytonwilliams.comwww.claytonwilliams.comorJaime
R. Casas, 432-688-3224Chief Financial Officer
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