ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited condensed consolidated financial statements as of
June 30, 2016
and for the
three and nine months ended
June 30, 2016
and
2015
included in this report and with our Annual Report on Form 10-K for the fiscal year ended
September 30, 2015
. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2015
and elsewhere in this report. See “Forward-Looking Statements” below.
OVERVIEW
The following discussion is intended to assist in understanding our financial position as of
June 30, 2016
, and our results of operations for the
three and nine months ended
June 30, 2016
and
June 30, 2015
. Financial and operating results for the three and
nine months ended
June 30, 2016
, include:
|
|
•
|
Operating revenues totaling
$228 million
and
$832 million
on
634
and
2,204
operating days for the
three and nine months ended
June 30, 2016
, respectively, as compared to operating revenues of
$331 million
and
$1 billion
on
991
and
3,003
operating days for the
three and nine months ended
June 30, 2015
, respectively;
|
|
|
•
|
Net income of
$100 million
and
$261 million
for the
three and nine months ended
June 30, 2016
, respectively, as compared to net income of
$113 million
and
$282 million
for the
three and nine months ended
June 30, 2015
, respectively;
|
|
|
•
|
Capital expenditures of
$198 million
for the
nine months ended
June 30, 2016
, as compared to capital expenditures of
$420 million
for the
nine months ended
June 30, 2015
; and
|
|
|
•
|
Increase in cash on hand of
$85 million
for the
nine months ended
June 30, 2016
to
$199 million
.
|
MARKET OUTLOOK
Industry Conditions
The level of activity in the offshore drilling industry, which affects the sector's profitability, is cyclical and highly dependent on the offshore capital expenditure levels of exploration and production ("E&P") companies. In turn, E&P company offshore drilling expenditures are influenced by the current prices of oil and gas, expectations about future prices, company-specific cash flow levels, historical project returns and other capital allocation strategies (e.g., onshore versus offshore drilling).
The offshore drilling industry has experienced declining demand for drilling rigs since the second half of calendar year 2014 due to a significant slowdown in E&P spending offshore that has been exacerbated by a sharp decline in oil prices. E&P companies generally reduced their offshore capital spending in 2015 and they are doing so again in calendar year 2016 by canceling or deferring planned drilling programs in accordance with lower budgets for offshore expenditures. Since declining to multi-year lows below $30 per barrel in January, oil prices have recovered to approximately
$45
per barrel in
July
. However, absent a further increase in oil prices, we expect offshore rig demand to decline into the second half of calendar year 2016 as offshore rigs complete existing contracts at a faster rate than new drilling programs are initiated. Declines in offshore drilling demand and the associated reductions in rig utilization and day rates, could materially and adversely affect our financial position, results of operation or cash flows. See "Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the volatility in oil and natural gas prices" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2015.
As offshore rig demand has declined over the past twenty months, drilling contractors have continued to take delivery of new, more capable rigs that were ordered prior to the current industry downturn. More recently, drilling contractors have delayed further rig deliveries through renegotiation of terms with the shipyards that are constructing these rigs. Due to the confluence of an oversupply of offshore rigs and declining rig demand, a lower percentage of marketed rigs are being re-contracted, and day rates and utilization have declined sharply across all offshore rig classes. While clients generally prefer newer, high specification rigs over older, less capable rigs, for both floaters and jackups, many newer, modern rigs have been idled or cold-stacked as drilling demand has declined across all regions, water depths and rig classes. However, the bifurcation trend of higher utilization and day rates for newer rigs has been maintained more consistently for floaters than for jackups during the current downturn.
Due to the uncertain duration of the current industry downturn, a growing number of older, less capable rigs have been scrapped or announced for scrapping, and this trend has accelerated thus far in calendar year 2016. However, even with the removal of
approximately 50 floaters and 25 jackups from the supply stack since 2014, further declines in rig utilization and day rates are possible due to the persistence of an offshore rig supply and demand imbalance.
Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of a specific drilling unit. Further declines in offshore drilling demand, and/or a lack of improvement in drilling activity or market day rates, may result in potential impairments to our drilling rigs and related equipment in the future. See "We may be required to record impairment charges with respect to our rigs" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2015.
A recent trend of some E&P companies to cancel, renegotiate, or repudiate existing drilling contracts has continued into 2016 as rig demand and market day rates decline further. In fiscal year 2015, we renegotiated four drilling contracts with respect to the
Atwood Osprey
,
Atwood Beacon
,
Atwood Achiever
and the
Atwood Orca
. These four agreements incorporated reduced day rates for some portion of the existing term in exchange for the extensions in the terms of the contracts. In March 2016, we negotiated with a client to shift their remaining contract backlog from the
Atwood Eagle
to the
Atwood Osprey
in order to preserve the continuity of operations for the
Atwood Osprey
. This shift in backlog did not alter the contractual day rate for the client, but it did lead to the immediate idling of the
Atwood Eagle
.
Some of our contracts with clients may be canceled at the option of the client upon payment of a termination fee which may not fully compensate us for the loss of the contract and may result in a rig being idled for an extended period of time. In addition, some of our clients could experience liquidity or solvency issues or could otherwise be unable or unwilling to perform under a contract, which could ultimately lead a client to enter bankruptcy or otherwise encourage a client to seek to repudiate, cancel or renegotiate a contract. Further deterioration in cash flow generation by E&P companies may accelerate these trends. If our clients seek to cancel or renegotiate our significant contracts and we are unable to negotiate favorable terms or secure new contracts on substantially similar terms, or at all, our revenues and profitability could be materially reduced. See "Our business may experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2015
.
Ultra-deepwater and Deepwater Rig Markets
Both the ultra-deepwater and deepwater rig markets are experiencing declining demand, utilization and day rates. As of
July 24, 2016
, the number of marketed ultra-deepwater rigs under contract industry-wide
decreased
to
104
(from
134
on
July 8, 2015
) representing
75%
utilization of a total of
138
active rigs. The number of marketed deepwater rigs under contract
decreased
to
20
(from
39
on
July 8, 2015
), representing
54%
utilization of a total of
37
active rigs. Declines in the percentage of marketed rigs under contract have been driven by reduced rig demand across all geographic regions coupled with an increase in marketed supply due to deliveries of newbuild rigs, primarily from Korean and Singaporean shipyards.
As of
July 24, 2016
,
32
ultra-deepwater floaters were under construction with scheduled deliveries through January 2020,
eight
of which were contracted. However, this figure includes
five
floaters under long-term contracts with Petrobras, many of which may be delayed, repudiated, or canceled due to the extensive financial difficulties of the primary Brazilian rig-owning entity. In response to reduced rig demand and lack of suitable drilling programs, we and other drilling contractors have proactively delayed delivery of ultra-deepwater rigs under construction.
Eight
ultra-deepwater rigs are scheduled for delivery during the remainder of calendar year 2016,
16
are scheduled for delivery in 2017 and an additional
eight
units are scheduled for delivery in 2018 and beyond.
The number of idle offshore rigs being cold-stacked and scrapped has continued to increase due to the unfavorable market conditions. During calendar year 2015,
16
ultra-deepwater rigs and
16
deepwater rigs were announced for cold-stacking, retirement or scrapping and are no longer being actively marketed. Through
July 24, 2016
,
18
ultra-deepwater rigs and
13
deepwater rigs were announced for cold-stacking, retirement or scrapping, reflecting an accelerating rate in calendar year 2016. We expect this trend of increasing marketed supply attrition to continue into the second half of calendar year 2016 as there are limited re-contracting opportunities for floaters completing their drilling programs, leading to a growing supply of idle rigs.
Our Ultra-deepwater Rigs and Deepwater Rigs
The
Atwood Achiever,
a dynamically positioned, ultra-deepwater drillship, is operating offshore Northwest Africa and is contracted through approximately November 2018. The client has an option, exercisable by February 2017, to revert the contract to its original end date of November 2017 by making a payment approximately equal to the difference in the original day rate for the time periods for which the current reduced operating day rate was invoiced. The
Atwood Advantage
, a dynamically positioned, ultra-deepwater drillship, is operating in the U.S. Gulf of Mexico and is contracted through August 2017.
The
Atwood Condor
, a dynamically positioned, ultra-deepwater semisubmersible, is operating in the U.S. Gulf of Mexico and is contracted through November 2016.
The
Atwood Osprey
, an ultra-deepwater semisubmersible and the
Atwood Eagle,
a deepwater semisubmersible, were both operating offshore Australia at the beginning of calendar 2016. On March 19, 2016, the
Atwood Eagle's
drilling services contract with Woodside Energy Ltd was mutually amended to assign and utilize the
Atwood Osprey
to perform drilling services for the remaining 165 days under contract. The
Atwood Osprey
is currently drilling the assigned program for Woodside Energy Ltd, and the material contractual terms and conditions of the
Atwood Eagle’s
original drilling services contract, including day rate, have remained unchanged. The
Atwood Eagle
has subsequently mobilized to Singapore where the rig is currently idle and being actively marketed for a new drilling contract.
The
Atwood Falcon
, a deepwater semisubmersible, was operating offshore Australia and was contracted through March 2016. Following contract completion and mobilization of the vessel to international waters, on March 24, 2016, we executed a sale and recycling agreement with a third party buyer for the purpose of selling the
Atwood Falcon.
The agreement requires the buyer to demolish and recycle the vessel and associated equipment/machinery. On April 13, 2016, the
Atwood Falcon
sale and recycling transaction closed and title of the vessel and associated equipment and machinery transferred to a third party buyer.
The
Atwood Admiral
and
Atwood Archer
are DP-3 dynamically-positioned, dual derrick, ultra-deepwater drillships rated to operate in water depths up to 12,000 feet and are currently under construction at the DSME shipyard in South Korea. These drillships will have enhanced technical capabilities, including two seven-ram BOPs, three 100-ton knuckle boom cranes, a 165-ton active heave “tree-running” knuckle boom crane and 200 person accommodations. Total cost, including project management, drilling and handling tools and spares, is approximately
$635 million
per drillship.
The
Atwood Admiral
and
Atwood Archer
were originally scheduled to be delivered in March 2015 and December 2015, respectively. Due to lack of suitable drilling programs, we have not yet secured the initial drilling contracts for these rigs. As a result, we have entered into amendments to our construction contracts with DSME to delay the required delivery date of these two rigs to September 30, 2017 and June 30, 2018, respectively. We are unable to provide any assurance that we will obtain drilling contracts for these rigs prior to their delivery. See Note 3 to our Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report for further details of these amendments.
Jackup Rig Market
The jackup market is experiencing similar utilization and day rate challenges as the floater market. Declining rig demand coupled with continued delivery of newbuild rigs, primarily from shipyards in China and Singapore, have negatively impacted the jackup rig supply and demand balance worldwide. In the current market downturn, all classes of jackup rigs have experienced lower day rates and utilization and the bifurcation trend that has historically favored utilization of new, higher specification jackups at the expense of older, lower specification jackups has not been maintained. Clients have become more price sensitive and fewer technically challenging wells are being drilled. As of
July 24, 2016
, the percentage of marketed high specification jackup rigs (i.e., rigs equal to or greater than 350-foot water depth capability) under contract was approximately
67%
as compared to
72%
for the remainder of the global jackup fleet.
We expect that the continued increase in global jackup supply due to the delivery of high specification newbuild rigs through the end of 2018 will put additional pressure on jackup rig utilization and day rates. As of
July 24, 2016
, there were
112
newbuild jackup rigs under construction (from
128
on
July 8, 2015
), most of which are being constructed in China and many of which are owned by speculators or the constructing shipyards. Of the
41
jackup rigs scheduled for delivery in the remainder of 2016, only
eight
are contracted, while the remaining
71
rigs are scheduled for delivery primarily in 2017 and beyond. Due to lack of sufficient rig demand to absorb this additional supply, some of these scheduled jackup deliveries are expected to be delayed and/or canceled. Absent a strong recovery in high specification jackup rig demand and/or a significant reduction in jackup rig supply due to cold-stacking, scrapping or retirements, the increasing marketed supply of jackups is likely to exceed client requirements for the foreseeable future.
The number of idle jackup rigs removed from the marketed rig supply increased significantly in calendar year 2015, as
eight
high specification jackups and
26
standard jackups were cold-stacked, scrapped or retired. Through
July 24, 2016
,
15
high specification jackups and
31
standard jackups, were cold-stacked, scrapped or retired, reflecting an accelerating rate over 2015 full-year levels. This trend of increasing marketed supply attrition is expected to continue into the second half of 2016 as older rigs are displaced due to declining overall jackup demand and increasing competition from newer, more capable rigs.
Our High Specification Jackup Rigs
The
Atwood Mako
and
Atwood Manta,
both 400-foot water depth Pacific Class jackup rigs, operated offshore Vietnam through September 2015 and offshore Thailand through October 2015, respectively. The
Atwood Mako
and
Atwood Manta
were idled in October 2015 after they completed their contracts and we were unable to obtain follow-on work. We are continuing to actively market these high-specification jackup rigs while they are currently idle.
The
Atwood Aurora
, a 350-foot water depth jackup, is operating offshore West Africa and is contracted through September 2016. The
Atwood Beacon
, a 400-foot water depth jackup, is operating in the Mediterranean Sea and is contracted into August 2016. The
Atwood Orca,
a 400-foot water depth Pacific Class jackup
is operating offshore Thailand and is contracted through October 2016.
Contract Backlog
We maintain a backlog of commitments for contract drilling revenues. Our contract backlog as of
June 30, 2016
was approximately
$0.8 billion
representing a
56%
decrease compared to our contract backlog of
$1.8 billion
as of
June 30, 2015
primarily due to realization of contract backlog. We calculate our contract backlog by multiplying the day rate under our drilling contracts by the number of days remaining under the contract, assuming full utilization. The calculation does not include any revenues related to mobilization, demobilization, contract preparation, and billing our clients for reimbursable items or bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including newbuild rig delivery dates, client elected standby periods unscheduled repairs, maintenance requirements, weather delays and other factors. Such factors may result in lower applicable day rates than the full contractual day rate and/or delays in receiving the full contractual operating rate. In addition, under certain circumstances, our clients may seek to terminate, repudiate or renegotiate our contracts, which could have the effect of reducing our contract backlog. See “Risks Related to our Business-Our business may experience reduced profitability if our clients terminate, repudiate, or renegotiate our drilling contracts” under Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2015
.
The following tables set forth the amount of our contract drilling revenue backlog and the percentage of available operating days committed for our fleet, excluding drilling units under construction and the
Atwood Falcon
which was sold in April 2016, for the periods indicated as of
June 30, 2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling Revenue Backlog
|
Remaining Fiscal 2016
|
|
Fiscal 2017
|
|
Fiscal 2018
|
|
Fiscal 2019
|
|
Fiscal 2020
|
|
Total
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Ultra-deepwater
|
$
|
191
|
|
|
$
|
391
|
|
|
$
|
181
|
|
|
$
|
21
|
|
|
$
|
—
|
|
|
$
|
784
|
|
Deepwater
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Jackups
|
24
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
Total
|
$
|
215
|
|
|
$
|
393
|
|
|
$
|
181
|
|
|
$
|
21
|
|
|
$
|
—
|
|
|
$
|
810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Available Operating Days Committed
|
Remaining Fiscal 2016
|
|
Fiscal 2017
|
|
Fiscal 2018
|
|
Fiscal 2019
|
|
Fiscal 2020
|
Ultra-deepwater
|
100
|
%
|
|
56
|
%
|
|
25
|
%
|
|
3
|
%
|
|
—
|
%
|
Deepwater
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
Jackups
|
42
|
%
|
|
2
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
Total
|
61
|
%
|
|
23
|
%
|
|
10
|
%
|
|
1
|
%
|
|
—
|
%
|
In July 2016, we signed two separate contracts to provide drilling services to clients operating in Australia for the
Atwood Osprey
. Assuming full utilization, total backlog will increase $128 million from $810 million reported as of June 30, 2016, with $9 million, $52 million, and $68 million of revenues expected to be recognized in fiscal years 2017, 2018 and 2019,
respectively. In addition, our percentage of available operating days committed increases 1%, 7%, and 10% for fiscal years 2017, 2018, and 2019, respectively.
RESULTS OF OPERATIONS
Revenues—
Revenues for the
three and nine months ended
June 30, 2016
decreased approximately
$103 million
and
$201 million
, respectively, or
31%
and
19%
, respectively, as compared to the
three and nine months ended
June 30, 2015
. An analysis of revenues by rig category is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Nine Months Ended June 30,
|
(In millions)
|
|
2016
|
|
2015
|
|
Variance
|
|
2016
|
|
2015
|
|
Variance
|
Ultra-Deepwater
|
|
$
|
182
|
|
|
$
|
174
|
|
|
$
|
8
|
|
|
$
|
553
|
|
|
$
|
524
|
|
|
$
|
29
|
|
Deepwater
|
|
—
|
|
|
77
|
|
|
(77
|
)
|
|
131
|
|
|
257
|
|
|
(126
|
)
|
Jackups
|
|
36
|
|
|
67
|
|
|
(31
|
)
|
|
111
|
|
|
212
|
|
|
(101
|
)
|
Reimbursable
|
|
10
|
|
|
13
|
|
|
(3
|
)
|
|
37
|
|
|
40
|
|
|
(3
|
)
|
|
|
$
|
228
|
|
|
$
|
331
|
|
|
$
|
(103
|
)
|
|
$
|
832
|
|
|
$
|
1,033
|
|
|
$
|
(201
|
)
|
Our ultra-deepwater fleet realized average revenues of
$500,000
per day on
364
operating days for the
three months ended
June 30, 2016
, as compared to $478,000 per day on 364 operating days for the
three months ended
June 30, 2015
. The ultra-deepwater fleet realized average revenues of
$514,000
per day on
1,076
operating days, as compared to $489,000 per day on 1,072 operating days for the
nine months ended
June 30, 2016
and 2015, respectively. The increase in revenues for the ultra-deepwater fleet for the
three and nine months ended
June 30, 2016
was due to the
Atwood Osprey
being on force majeure rate during the third quarter of 2015 as a result of a tropical cyclone, and the
Atwood Achiever
operating for the entire 2016 period.
Our deepwater fleet did not operate in the third quarter 2016, as compared to the
three months ended
June 30, 2015
, which operated the fleet for 177 days at $435,000 per day. The deepwater fleet realized average revenues of
$426,000
per day on
307
operating days as compared to $424,000 per day on 606 operating days for the
nine months ended
June 30, 2016
and
2015
, respectively. The decrease in operating days and revenue for fiscal year 2016, compared to fiscal year 2015, is primarily due to
Atwood Falcon
and
Atwood Eagle
completing their contracts in fiscal year 2016. The
Atwood Falcon
was idled and subsequently sold for recycling purposes, while the
Atwood Eagle
’s contract was suspended and remaining term transferred to the
Atwood Osprey
.
Our jackup fleet realized average revenues of
$132,000
per day on
270
operating days for the
three months ended
June 30, 2016
, as compared to $149,000 per day on 450 operating days for
three months ended
June 30, 2015
. The jackup fleet realized average revenues of
$135,000
per operating day on
821
operating days, as compared to $160,000 per operating day on 1,325 operating days for the
nine months ended
June 30, 2016
and
2015
, respectively. The jackup fleet realized lower revenue and operating days for the
three and nine months ended
June 30, 2016
, as compared to
three and nine months ended
June 30, 2015
primarily due to the
Atwood Manta
and the
Atwood Mako
being idled in October 2015.
Revenue related to reimbursable expenses is primarily driven by our clients’ requests for equipment, fuel, services and/or personnel that are not included in the contractual operating day rate. Thus, these revenues vary depending on the timing of the clients’ requests and the work performed. Additionally, as a result of a certain number of our rigs being idled, reimbursable revenue naturally declines while the rigs remain un-contracted. Changes in the amount of revenue related to reimbursable expenses generally do not have a material effect on our financial position, results of operations, or cash flows.
Drilling Costs—
Drilling costs for the
three and nine months ended
June 30, 2016
decreased approximately
$57 million
and
$108 million
, respectively, or
40%
and
25%
, respectively, as compared to the
three and nine months ended
June 30, 2015
. An analysis of contract drilling costs by rig category is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DRILLING COSTS
|
|
Three Months Ended June 30,
|
|
Nine Months Ended June 30,
|
(In millions)
|
2016
|
|
2015
|
|
Variance
|
|
2016
|
|
2015
|
|
Variance
|
Ultra-Deepwater
|
$
|
54
|
|
|
$
|
75
|
|
|
$
|
(21
|
)
|
|
$
|
168
|
|
|
$
|
206
|
|
|
$
|
(38
|
)
|
Deepwater
|
10
|
|
|
29
|
|
|
(19
|
)
|
|
71
|
|
|
102
|
|
|
(31
|
)
|
Jackups
|
16
|
|
|
29
|
|
|
(13
|
)
|
|
62
|
|
|
91
|
|
|
(29
|
)
|
Reimbursable
|
5
|
|
|
9
|
|
|
(4
|
)
|
|
23
|
|
|
30
|
|
|
(7
|
)
|
Other
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
(3
|
)
|
|
$
|
86
|
|
|
$
|
143
|
|
|
$
|
(57
|
)
|
|
$
|
324
|
|
|
$
|
432
|
|
|
$
|
(108
|
)
|
Ultra-deepwater drilling costs decreased for the
three and nine months ended
June 30, 2016
, as compared to the
three and nine months ended
June 30, 2015
. Average drilling costs per calendar day for our ultra-deepwater rigs decreased from approximately $205,000 for the
three months ended
June 30, 2015
, to approximately
$148,000
for the
three months ended
June 30, 2016
, and from $190,000 for the
nine months ended
June 30, 2015
, to
$153,000
for the
nine months ended
June 30, 2016
. The drilling costs for our ultra-deepwater rigs were lower in 2016 due to cost saving initiatives executed on payroll, and lower repairs and maintenances costs. Additionally, repair costs in fiscal year 2015 were higher due to the unplanned repair costs incurred on the
Atwood Osprey
as a result of damages from Tropical Cyclone Olwyn.
Deepwater drilling costs decreased for the
three and nine months ended
June 30, 2016
, as compared to the
three and nine months ended
June 30, 2015
. Average drilling costs per calendar day for our deepwater rigs decreased from approximately $160,000 for the
three months ended
June 30, 2015
, to approximately
$96,000
for
three months ended
June 30, 2016
, and $160,000 for the
nine months ended
June 30, 2015
, to
$151,000
for the
nine months ended
June 30, 2016
. This decrease is primarily due to the contract completion of the
Atwood Falcon
and
Atwood Eagle
, resulting in lower costs in fiscal year 2016.
Jackup drilling costs decreased for the
three and nine months ended
June 30, 2016
, as compared to the
three and nine months ended
June 30, 2015
, primarily due to the
Atwood Mako
and
Atwood Manta
being idled in October 2015. The average drilling cost per calendar day decreased from approximately $65,000 for the
three months ended
June 30, 2015
, to approximately
$35,000
for the
three months ended
June 30, 2016
, and $65,000 for the
nine months ended
June 30, 2015
, to
$45,000
for the
nine months ended
June 30, 2016
.
Reimbursable costs are primarily driven by our clients’ requests for equipment, fuel, services and/or personnel that are not typically included in the contractual operating day rate. Thus, these costs vary depending on the timing of the clients’ requests and the work performed. Additionally, as a result of a certain number of our rigs being idled, reimbursable costs naturally declines while the rigs remain un-contracted. Changes in the amount of reimbursable costs generally do not have a material effect on our financial position, results of operations or cash flows.
Depreciation
—Depreciation expense for the
three and nine months ended
June 30, 2016
decreased approximately
$1 million
and
$5 million
, respectively, or
2%
and
4%
, respectively, as compared to the
three and nine months ended
June 30, 2015
. This decrease is primarily due to the impairment of the
Atwood Hunter
as a result of it being idled in December 2014 and the
Atwood Falcon
, which was impaired in December 2015. An analysis of depreciation expense by rig category is as follows:
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DEPRECIATION EXPENSE
|
|
Three Months Ended June 30,
|
|
Nine Months Ended June 30,
|
(In millions)
|
2016
|
|
2015
|
|
Variance
|
|
2016
|
|
2015
|
|
Variance
|
Ultra-Deepwater
|
$
|
29
|
|
|
$
|
28
|
|
|
$
|
1
|
|
|
$
|
87
|
|
|
$
|
85
|
|
|
$
|
2
|
|
Deepwater
|
2
|
|
|
4
|
|
|
(2
|
)
|
|
7
|
|
|
13
|
|
|
(6
|
)
|
Jackups
|
9
|
|
|
9
|
|
|
—
|
|
|
26
|
|
|
27
|
|
|
(1
|
)
|
Other
|
1
|
|
|
2
|
|
|
(1
|
)
|
|
5
|
|
|
5
|
|
|
—
|
|
|
$
|
41
|
|
|
$
|
43
|
|
|
$
|
(2
|
)
|
|
$
|
125
|
|
|
$
|
130
|
|
|
$
|
(5
|
)
|
Deepwater depreciation decreased $2 million and $6 million for the
three and nine months ended
June 30, 2016
, as compared to the
three and nine months ended
June 30, 2015
, respectively, due to the impairment of the
Atwood Hunter
in December 2014, and the impairment of the
Atwood Falcon
in December 2015
.
Asset Impairment—
During the
nine months ended
June 30, 2016
, we recorded a non-cash impairment charge of approximately
$64.8 million
(
$64.8 million
, net of tax, or
$1.00
per diluted share) to write the
Atwood Falcon
and its inventory of materials and supplies down to their approximate salvage value. See Note 3 to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
During the
nine months ended
June 30, 2015
, we recorded a non-cash impairment charge of approximately
$60.8 million
(
$56.1 million
, net of tax, or
$0.86
per diluted share) to write the
Atwood Hunter
and its inventory of materials and supplies down to their salvage value. See Note 3 to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.
General and Administrative—
For the
three months ended
June 30, 2016
, general and administrative expenses increased by approximately $1.5 million to
$12.0 million
, as compared to
$10.5 million
for the
three months ended
June 30, 2015
. This increase was primarily due to both lower payroll related costs during the
three months ended
June 30, 2015
, as a result of share-based compensation adjustments, as well as, an increase in employee related expenses associated with a non-competition and non-solicitation agreement entered into with certain employees during the quarter. For the
nine months ended
June 30, 2016
, general and administrative expenses decreased by approximately $
3.9 million
to
$38.7 million
, as compared to
$42.6 million
for the
nine months ended
June 30, 2015
. This decrease was primarily due to reductions in payroll and related costs associated with several company-wide cost saving measures.
Loss on sale of assets—
Our loss on sale of assets for the
nine months ended
June 30, 2015
was primarily due to a loss of approximately
$8.0 million
(
$7.1 million
, net of tax, or
$0.11
per diluted share) due to the sale of the
Atwood Southern Cross
and a loss of approximately $5.5 million ($5.5 million, net of tax, or $0.08 per diluted share), due to the sale of
Atwood Hunter
.
Interest Expense, net of capitalized interest—
For the
nine months ended
June 30, 2016
, interest expense, net of capitalized interest, increased by approximately
$10.5 million
to
$50.5 million
, as compared to
$40.0 million
for the
nine months ended
June 30, 2015
, primarily due to a higher interest rate on our Credit Facility borrowings and lower capitalized interest in the
three months ended
June 30, 2016
.
Gains on extinguishment of debt—
During the
nine months ended
June 30, 2016
, we repurchased, through open market transactions,
$159.3 million
aggregate principal amount of our Senior Notes at an aggregate cost of
$102.5 million
, including accrued interest. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of debt issuance costs and premium, of
$58.9 million
(
$44.1 million
net of tax, or
$0.68
per diluted share) in Gains on extinguishment of debt on the Condensed Consolidated Statement of Operations for the
nine months ended
June 30, 2016
. The repurchases were made using available cash balances.
Other Income—
During the three months ended December 31, 2015, we recognized approximately
$18.0 million
(
$18.0 million
, net of tax, or
$0.28
per diluted share) of additional expected insurance recoveries related to cyclone damage to the
Atwood Osprey
. This amount is included in Other Income on the Condensed Consolidated Statement of Operations for the
nine months ended
June 30, 2016
. We collected receivables from the insurance company of approximately
$6.7 million
and
$11.8 million
during the three month periods ending March 31, 2016 and June 30, 2016, respectively, which are reflected as cash proceeds from investing in the Condensed Consolidated Statement of Cash Flows.
Income Taxes—
Our consolidated effective income tax rate for the
three and nine months ended
June 30, 2016
was approximately
17%
and
15%
, as compared to for
8%
and
10%
, the
three and nine months ended
June 30, 2015
. The effective tax rate for the
three and nine months ended
June 30, 2016
was higher than the rate for the
three and nine months ended
June 30, 2015
, primarily due to the U.S. income tax associated with the
$58.9 million
of gain recognized from the retirement of debt. During the quarter, as a consequence of the aforementioned gain coupled with increased profitability from our US Gulf of Mexico operations, we fully utilized our deferred tax asset related to our U.S. net operating loss carry-forward and we reversed the valuation allowance associated with that deferred tax asset. Our effective tax rate was lower than the U.S. statutory rate of
35%
as a result of working in certain lower tax jurisdictions outside the United States.
LIQUIDITY AND CAPITAL RESOURCES
Sources of Liquidity
Our sources of available liquidity include existing cash balances on hand, cash flows from operations and borrowings under our Credit Facility. In addition, we may seek to access the debt and equity capital markets in the future to raise additional capital, increase liquidity as necessary, fund additional purchases, exchanges or redemptions of Senior Notes, repay amounts under our Credit Facility or otherwise refinance existing debt. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, industry conditions, general economic conditions, our revenue backlog, capital expenditure commitments, market conditions and market perceptions of us and our industry.
Our liquidity requirements include meeting ongoing working capital needs, repaying our outstanding indebtedness, and funding our capital expenditure projects. Our ability to meet these liquidity requirements will depend in large part on our future operating and financial performance.
Our cash flow fluctuates depending on a number of factors, including, among others, the number of our drilling units under contract, the day rates that we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, payments to our vendors for operating costs, and capital expenditures. We have instituted several company-wide cost savings measures, including the elimination of non-essential personnel and other operational measures, including delaying certain capital expenditure projects to reduce liquidity requirements to a level consistent with the size of our anticipated fleet operating under client contracts over the next twelve months. These activities have had and continue to have a positive impact on our cash flow generation and overall liquidity. We believe that our cash on hand, cash flows generated from operating activities and available borrowings under our Credit Facility will provide sufficient liquidity over the next twelve months to fund our working capital needs, scheduled interest payments on our outstanding debt and other purposes.
As of
June 30, 2016
, we had
$199.0 million
in cash on hand. During the
nine months ended
June 30, 2016
, we relied principally on our cash flows from operations and cash on hand to meet liquidity needs and fund our cash requirements including our capital expenditures of
$198.2 million
. To date, general inflationary trends have not had a material effect on our operating revenues or expenses.
Cash Flows
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30,
|
(In millions)
|
2016
|
|
2015
|
Net cash provided by operating activities
|
$
|
515,415
|
|
|
$
|
483,605
|
|
Net cash used in investing activities
|
(177,435
|
)
|
|
(417,738
|
)
|
Net cash used in financing activities
|
(252,989
|
)
|
|
(71,443
|
)
|
Working capital decreased from
$470.5 million
as of
September 30, 2015
to
$410.6 million
as of
June 30, 2016
. Net cash from operating activities for the
nine months ended
June 30, 2016
was
$515.4 million
, as compared to $
483.6 million
for the
nine months ended
June 30, 2015
.
Investing Activities
Capital Expenditures
Our investing activities are primarily related to capital expenditures for property and equipment. Our capital expenditures, including maintenance capital expenditures, for the
nine months ended
June 30, 2016
totaled
$198.2 million
. Our capital expenditures for the
nine months ended
June 30, 2015
totaled
$420.1 million
.
As of
June 30, 2016
, we have expended approximately
$795 million
on our drilling units under construction. The
Atwood Admiral
and
Atwood Archer
were originally scheduled to be delivered in March 2015 and December 2015, respectively. On December 17, 2015, we entered into a supplemental agreement No. 4 ("Supplemental Agreement No. 4") for each rig with Daewoo Shipbuilding and Marine Engineering Co., Ltd ("DSME"), which delayed the required delivery date for these rigs to September 30, 2017 and June 30, 2018, respectively. Supplemental Agreement No. 4 superseded all previous agreements. In consideration of the agreement, we made a payment of
$50 million
for each drillship on December 31, 2015. All remaining milestone payments,
$93.9 million
for the
Atwood Admiral
and
$305.9 million
for the
Atwood
Archer,
have been extended until their respective delivery dates. We believe that we will be able to fund all additional construction costs with cash flow from operations and borrowings under our Credit Facility. As of
June 30, 2016
, we estimate the remaining costs including firm commitments, project management, capitalized interest, drilling tools, handling tools and spares for our drilling units under construction to be
$460 million
.
Financing Activities
Our financing activities primarily consist of borrowing and repayment of long-term and short-term debt and dividend payments. Proceeds received from borrowings from our Credit Facility totaled
$45 million
for the
nine months ended
June 30, 2016
. Repayments on our Credit Facility totaled
$190 million
for the
nine months ended
June 30, 2016
.
Dividends
We paid a dividend of $0.075 per share in January 2016, that was declared in November 2015. In February 2016, our board of directors eliminated the payment of a quarterly dividend in order to preserve liquidity. The March 2016 amendment to our Credit Facility revised the restricted payments covenant to prohibit us from paying dividends during the term of the facility. Future reinstatement of dividends would require the amendment or waiver of such provision. In addition, the declaration and amount of any future dividends would be at the discretion of our board of directors and would depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our board of directors deemed relevant. There can be no assurance that we will pay a dividend in the future.
Senior Notes (Due February 2020)
As of
June 30, 2016
,
$490.7 million
aggregate principal amount of our Senior Notes were outstanding. Ou
r Senior Notes are unsecured obligations and are not guaranteed by any of our subsidiaries.
During the
nine months ended
June 30, 2016
, we repurchased, through open market transactions
$159.3 million
aggregate principal amount of our Senior Notes at an aggregate cost of
$102.5 million
, including accrued interest. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of debt issuance costs and premium, of
$58.9 million
(
$44.1 million
net of tax, or
$0.68
per diluted share) in Gains on extinguishment of debt on the Condensed Consolidated Statements of Operations for the
nine months ended
June 30, 2016
. The repurchases were made using available cash balances.
These repurchases, allowed us to reduce our outstanding indebtedness and related interest expense at a significant discount to the face value of our Senior Notes. The gain associated with the repurchases is subject to tax and will increase our effective tax rate. However, due to the availability of operating loss carry-forwards the actual cash tax impact will be minimal. The repurchases were made using available cash balances. Following these repurchases, the Company has
$490.7 million
Senior Notes outstanding.
On June 24, 2016, we commenced a modified "Dutch Auction" tender offer (the "Offer") for up to $150,000,000 aggregate principal amount of our outstanding Senior Notes. On July 25, 2016, we acquired
$42.0 million
aggregate principal amount of the Senior Notes pursuant to the Offer. Including the purchase price for the Senior Notes, which totaled
$31.5 million
, and accrued interest payable on the Senior Notes acquired and related fees, the total cost of the Offer was
$33.0 million
which was funded by available cash balances. As of July 25, 2016, following consummation of the Offer, the Company had
$448.7 million
aggregate principal amount of Senior Notes outstanding. The purchase price in the Offer represented a discount to the principal amount of the Senior Notes of
25.0%
.
From time to time, we may purchase additional Senior Notes in the open market, in privately negotiated transactions, through tender offers, exchange offers or otherwise, or we may redeem Senior Notes in whole or in part at the redemption price set forth in the indenture governing the Senior Notes. Any future purchases, exchanges or redemptions will depend on various factors existing at that time. There can be no assurance as to which, if any, of these alternatives (or combinations thereof) we may choose to pursue in the future, and there can be no assurance that an active trading market will exist for the Senior Notes following any such transactions.
Revolving Credit Facility
On March 25, 2016, we entered into an amendment to our Credit Facility providing that, among other things, effective on March 28, 2016, (i) removes the maximum leverage ratio and maximum secured leverage ratio financial covenants, (ii) amends the minimum interest expense coverage ratio such that it is not applicable until the quarter ending September 30, 2018, and decreases the minimum ratio required to 1.15:1.00, (iii) adds a minimum liquidity financial covenant of $150 million, (iv) revises the restricted payments covenant to prohibit us from paying dividends, (v) reduces the total commitments under the Credit Facility by $152 million, and (vi) permits the incurrence of up to $400 million of second lien debt, subject to the parameters set forth therein. After giving effect to the amendment, commitments under the Credit Facility are $1.395 billion through May 2018 and $1.1205 billion through May 2019. As a result of the amendment, borrowings under the Credit Facility will bear interest at the Eurodollar rate plus a margin ranging from 2.50% to 3.25% and the commitment fee on the unused portion of the underlying commitment ranges from 1.00% to 1.30% per annum, in each case based on our corporate credit ratings.
In connection with the amendment, we mortgaged the
Atwood Achiever
, the
Atwood Advantage
and the
Atwood Orca
, as additional collateral under the Credit Facility, as well as pledged the equity interests in the subsidiaries of the Company that own, directly or indirectly, these three vessels. Additionally, the
Atwood Eagle
and
Atwood Falcon
, along with the pledged equity interests in certain of our subsidiaries that, directly or indirectly, own these two vessels, were removed as collateral under the Credit Facility. On April 13, 2016, the
Atwood Falcon
sale and recycling transaction closed and title of the vessel and associated equipment and machinery transferred to a third party buyer. Our interest in the two drillships under construction remain unencumbered by the Credit Facility.
As of
June 30, 2016
, our Credit Facility had
$1.395 billion
of total commitments and we had
$885 million
of outstanding borrowings. As of
June 30, 2016
, we had approximately
$510 million
available for borrowings under the Credit Facility. Approximately
$275 million
of the commitments mature in May 2018 and approximately
$1.12 billion
of the commitments under the Credit Facility mature in May 2019.
Obligations under the Credit Facility are secured primarily by first preferred mortgages on nine of our drilling units (
Atwood
Aurora
,
Atwood
Beacon
,
Atwood
Condor,
Atwood
Mako,
Atwood
Manta, Atwood
Osprey, Atwood Achiever
,
Atwood Advantage
and
Atwood Orca
), as well as liens on the equity interests of our subsidiaries that own, directly or indirectly, such drilling units. We were in compliance with all financial covenants under the Credit Facility as of
June 30, 2016
and we anticipate that we will continue to be in compliance for the remainder of 2016. See "Covenants in our debt agreements restrict our ability to engage in certain activities" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended
September 30, 2015
.
The weighted-average effective interest rate on our long-term debt was approximately
4.4%
per annum as of
June 30, 2016
. The effective rate was determined after giving consideration to the effect of our interest rate swaps accounted for as hedges and the amortization of debt issuance costs and our debt premiums. Interest capitalized for the
three and nine months ended
June 30, 2016
was approximately
$4 million
and
$13 million
respectively. Interest capitalized for the
three and nine months ended
June 30, 2015
was approximately
$6 million
and
$15 million
respectively.
The following summarizes our availability under our Credit Facility as of
June 30, 2016
(in millions):
|
|
|
|
|
Commitment under Credit Facility
|
$
|
1,395
|
|
Borrowings under Credit Facility
|
885
|
|
Letters of Credit Outstanding
|
—
|
|
Availability
|
$
|
510
|
|
Letter of Credit Facility
In July 2015, we entered into a letter of credit facility with BNP Paribas (“BNP”), pursuant to which BNP may issue letters of credit up to an unlimited stated face amount of such letters of credit. BNP has no commitment under the facility to issue letters of credit, and the facility may be canceled by BNP at any time. The facility contains certain events of default, including but not limited to delinquent payments, bankruptcy filings, material adverse judgments, cross-defaults under other debt agreements, or a change of control. As of
June 30, 2016
, we have not requested any letters of credits under this facility.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
Commitments and Contractual Obligations
In May 2016, we entered into an agreement with Hydril USA Distribution, LLC ("GE") to manufacture a complete second Blowout Preventer stack ("BOP") and an Auxiliary Stack Test System ("ASTS") for the
Atwood Condor
. The addition of the second BOP will increase the marketability and operational efficiency of the vessel. Total consideration for this agreement is approximately $19 million with 20% due upon placement of the purchase order and the remaining 80% due upon delivery. To accelerate the manufacturing and delivery process, which is targeted for February 2017, we provided certain capital spares we maintained to GE to be used in the manufacturing process. These capital spares will be replenished by GE with similar capital spares upon delivery of the BOP.
For additional information about our commitments and contractual obligations as of
June 30, 2016
, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contractual Obligations” in our
Annual Report on Form 10-K for the fiscal year ended
September 30, 2015
. As of
June 30, 2016
, other than payments made under our construction contracts, further postponement of the required delivery of the drilling units under construction, repayments under our Credit Facility, and the purchase of the second BOP and ASTS equipment mentioned above, there were no material changes to this disclosure regarding our commitments and contractual obligations.
FORWARD-LOOKING STATEMENTS
Statements included in this Form 10-Q regarding future financial performance, capital sources and results of operations and other statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are 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. Such statements are those concerning strategic plans, expectations and objectives for future operations and performance. When used in this report, the words “believes,” “expects,” “anticipates,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions are intended to be among the statements that identify forward-looking statements.
Such statements are subject to numerous risks, uncertainties and assumptions that are beyond our ability to control, including, but not limited to:
|
|
•
|
prices of oil and natural gas and industry expectations about future prices;
|
|
|
•
|
market conditions and level of activity in the drilling industry and the global economy in general;
|
|
|
•
|
the level of capital expenditures by our clients;
|
|
|
•
|
the termination, renegotiation, or repudiation of contracts or payment delays by our clients;
|
|
|
•
|
the operational risks involved in drilling for oil and gas;
|
|
|
•
|
the highly competitive and volatile nature of our business;
|
|
|
•
|
our ability to enter into, and the terms of, future drilling contracts, including contracts for our newbuild units, for rigs currently idled and for rigs whose contracts are expiring;
|
|
|
•
|
our ability to access debt and equity capital markets, and the terms and prices that are available if we issue debt or equity securities;
|
|
|
•
|
the impact of governmental or industry regulation, both in the United States and internationally;
|
|
|
•
|
the risks of and disruptions to international operations, including political instability and the impact of terrorist acts, acts of piracy, embargoes, war or other military operations;
|
|
|
•
|
our ability to obtain and retain qualified personnel to operate our vessels;
|
|
|
•
|
unplanned downtime and repairs on our rigs;
|
|
|
•
|
timely access to spare parts, equipment and personnel to maintain and service our fleet;
|
|
|
•
|
client requirements for drilling capacity and client drilling plans;
|
|
|
•
|
the adequacy of sources of liquidity for us and for our clients;
|
|
|
•
|
changes in tax laws, treaties and regulations;
|
|
|
•
|
the risks involved in the construction, upgrade, and repair of our drilling units; and
|
|
|
•
|
such other risks discussed in Item 1A. “Risk Factors” of our Form 10-K for the fiscal year ended September 30, 2015 and in our other reports filed with the Securities and Exchange Commission, or SEC.
|
Forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. Undue reliance should not be placed on these forward-looking statements, which are applicable only on the date hereof. We undertake no obligation to revise or update these forward-looking statements to reflect events or circumstances that arise after the date hereof or to reflect the occurrence of unanticipated events.