|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.
General
We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of California. We were incorporated in Delaware as a wholly owned subsidiary of Occidental Petroleum Corporation (Occidental) on April 23, 2014, and remained a wholly owned subsidiary of Occidental until November 30, 2014. Prior to November 30, 2014, all material existing assets, operations and liabilities of Occidental's California business were consolidated under CRC. On November 30, 2014, Occidental distributed shares of our common stock on a pro rata basis to Occidental stockholders and we became an independent, publicly traded company (the Spin-off). Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which it distributed to Occidental stockholders on March 24, 2016.
On May 31, 2016 we completed a reverse stock split using a ratio of one share of common stock for every ten shares then outstanding.
In August 2016, we issued a new $1 billion first lien, second out term loan credit facility to prepay a portion of the existing term loans and revolving loans under our first lien, first out credit facility. Additionally, we tendered for and repurchased $1.4 billion in aggregate principal amount of our senior unsecured notes for $750 million using our existing revolver, resulting in a $660 million pre-tax gain, net of related expenses. This tender offer resulted in a net debt reduction of $625 million.
Business Environment and Industry Outlook
Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly, generally as a result of changes in supply and demand and other market-related uncertainties. These and other factors make it impossible to predict realized prices reliably. Much of the global exploration and production industry is challenged at current price levels, putting pressure on the industry's ability to generate positive cash flow and access capital. Average oil prices continued the decline that began in the last half of 2014 into the first quarter of 2016. While global oil prices improved modestly through the third quarter of 2016 and started to trade in a narrower range, they were still lower in the three and nine months ended September 30, 2016 compared to the same periods in 2015.
Natural gas liquids (NGLs) prices have improved relative to crude oil prices over the last 12 months due to tighter supplies and higher contract prices on natural gasoline.
Natural gas prices remained lower in the three and nine months ended September 30, 2016 than comparable periods in 2015. However, prices rebounded strongly in the second half of the year due to lower production, higher demand and warmer weather. California natural gas differentials for the second half of the year also started to improve primarily due to reduced storage in the state.
The following table presents the average daily Brent, WTI and NYMEX prices for the
three and nine
months ended
September 30, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Brent oil ($/Bbl)
|
$
|
46.98
|
|
|
$
|
51.17
|
|
|
$
|
43.01
|
|
|
$
|
56.61
|
|
WTI oil ($/Bbl)
|
$
|
44.94
|
|
|
$
|
46.43
|
|
|
$
|
41.33
|
|
|
$
|
51.00
|
|
NYMEX gas ($/Mcf)
|
$
|
2.70
|
|
|
$
|
2.78
|
|
|
$
|
2.24
|
|
|
$
|
2.86
|
|
Oil prices and differentials will continue to be affected by a variety of factors, including consumption patterns, inventory levels, global and local economic conditions, the actions of OPEC and other significant producers and governments, actual or threatened production and refining disruptions, currency exchange rates, worldwide drilling and exploration activities, the effects of conservation, weather, geophysical and technical limitations, refining and processing disruptions, transportation bottlenecks and other matters affecting the supply and demand dynamics for oil, technological advances, regional market conditions, transportation capacity and costs in producing areas and the effect of changes in these variables on market perceptions.
We currently sell all of our crude oil into the California refining markets, which we believe have offered relatively favorable pricing compared to other U.S. regions for similar grades. California imports over 60% of its oil. A vast majority of the oil is imported via supertanker, with a negligible amount arriving by rail. As a result, California refiners have typically purchased crude oil at international waterborne-based prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will continue contributing to higher realizations than most other U.S. oil markets for comparable grades. Beginning in late 2015, the U.S. federal government allowed the export of crude oil. We are opportunistically pursuing newly opened export markets to improve our margins.
Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.
Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Capacity influences prices because California imports about 90% of its natural gas from other parts of the U.S. As a result, we typically enjoy favorable pricing against the NYMEX index since we can deliver our gas for much lower transportation costs. Due to much lower levels of natural gas production compared to our oil production, the changes in natural gas prices have a lower impact on our operating results.
Higher natural gas prices have a net positive effect on our operating results. In addition to selling natural gas, we also use gas for our steamfloods and power generation. As a result, any positive impact of higher prices is partially offset by higher operating costs. Conversely, lower natural gas prices generally have a net negative effect on our operations, but lower the cost of our steamflood projects and power generation.
Our earnings are also affected by the performance of our processing and power generation assets. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Additionally, we provide part of the electricity output from our Elk Hills power plant to reduce operating costs to Elk Hills and nearby fields and increase reliability.
We opportunistically seek strategic hedging transactions to protect our cash flows, margins and capital investment programs from the cyclical nature of commodity prices and to improve our ability to comply with our credit facility covenants. We can give no assurances that our hedges will be adequate to accomplish our objectives. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not necessarily accounted for as cash-flow or fair-value hedges.
We respond to economic conditions by adjusting the size and allocation of our capital program, aligning the size of our workforce with the level of activity, continuing to improve efficiencies and cost savings and working with our suppliers and service providers to adjust the cost of goods and services to reflect current market pricing. The reductions in our capital program will negatively impact our production levels in the near term and sustained low-price periods may materially affect the quantities of oil and gas reserves we can economically produce over the longer term.
Seasonality
While certain aspects of our operations are affected by seasonal factors, such as electricity costs, overall, seasonality is not a material driver of changes in our quarterly results during the year.
Operations
We conduct our operations through fee interests, land leases and other contractual arrangements. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.4 million net acres, approximately 60% of which we hold in fee. Our oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. We also own a network of strategically placed infrastructure that is integrated with our operations, including gas plants, oil and gas gathering systems, a power plant and other related assets, to maximize the value generated from our production.
Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and production costs. We record a share of production and reserves to recover such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (1) to recover our partners’ share of capital and production costs that we incur on their behalf, (2) for our share of contractually defined base production and (3) for our share of production in excess of contractually defined base production for each period. We realize our share of capital and production costs, and generate returns, through our defined share of production from (2) and (3) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, however, our net economic benefit is greater when product prices are higher. The contracts represented slightly less than 20% of our production for the quarter ended
September 30, 2016
.
Fixed and Variable Costs
Our total production costs consist of variable costs that tend to vary depending on production levels, and fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. While a certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. Overall, we believe less than one-third of our operating costs are fixed over the life cycle of our fields. We actively manage our fields to optimize production and costs. When we see growth in a field we increase capacities, and similarly when a field nears the end of its economic life we manage the costs while it remains economically viable to produce.
Financial and Operating Results
Third Quarter 2016 compared to Third Quarter 2015
|
|
•
|
Net income of $546 million reflected a net gain of $660 million on early extinguishment of debt.
|
|
|
•
|
Adjusted net loss decreased 17% from
$86 million
to $71 million.
|
|
|
•
|
Average daily oil and gas production volumes decreased 13% from 158,000 to 138,000 barrels of oil equivalent (Boe).
|
|
|
•
|
Realized crude oil prices, including the effect of cash received from settled hedges, decreased 10% from
$47.79
to $43.03 per barrel.
|
|
|
•
|
Production costs decreased 14% from
$246 million
to $211 million.
|
First Nine Months of 2016 compared to First Nine Months of 2015
|
|
•
|
Net income of $356 million reflected a net gain of $793 million on early extinguishment of debt.
|
|
|
•
|
Adjusted net loss increased 4% from
$234 million
to $243 million.
|
|
|
•
|
Average daily oil and gas production volumes decreased 12% from 161,000 to 142,000 Boe.
|
|
|
•
|
Realized crude oil prices, including the effect of cash received from settled hedges, decreased 19% from
$50.28
to $40.91 per barrel.
|
|
|
•
|
Production costs decreased 20% from
$730 million
to $583 million.
|
The table below reconciles net income (loss) to adjusted net loss and presents net and adjusted net loss per diluted share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Net income (loss)
|
$
|
546
|
|
|
$
|
(104
|
)
|
|
$
|
356
|
|
|
$
|
(272
|
)
|
Non-cash, unusual and infrequent items:
|
|
|
|
|
|
|
|
Non-cash derivative losses (gains)
|
25
|
|
|
(53
|
)
|
|
243
|
|
|
(33
|
)
|
Severance and early retirement costs
|
1
|
|
|
62
|
|
|
19
|
|
|
72
|
|
Plant turnaround, outage and other costs
|
5
|
|
|
3
|
|
|
14
|
|
|
6
|
|
Net gain on early extinguishment of debt
|
(660
|
)
|
|
—
|
|
|
(793
|
)
|
|
—
|
|
Gain from asset divestitures
|
—
|
|
|
—
|
|
|
(31
|
)
|
|
—
|
|
Adjusted income items before interest and taxes
|
(629
|
)
|
|
12
|
|
|
(548
|
)
|
|
45
|
|
Deferred debt issuance costs write-off
|
12
|
|
|
—
|
|
|
12
|
|
|
—
|
|
Valuation allowance for deferred tax assets
(a)
|
—
|
|
|
—
|
|
|
(63
|
)
|
|
—
|
|
Tax effects of these items
|
—
|
|
|
6
|
|
|
—
|
|
|
(7
|
)
|
Total
|
(617
|
)
|
|
18
|
|
|
(599
|
)
|
|
38
|
|
Adjusted net loss
|
$
|
(71
|
)
|
|
$
|
(86
|
)
|
|
$
|
(243
|
)
|
|
$
|
(234
|
)
|
|
|
|
|
|
|
|
|
Net income (loss) per diluted share
|
$
|
13.06
|
|
|
$
|
(2.72
|
)
|
|
$
|
8.79
|
|
|
$
|
(7.10
|
)
|
Adjusted net loss per diluted share
|
$
|
(1.75
|
)
|
|
$
|
(2.25
|
)
|
|
$
|
(6.12
|
)
|
|
$
|
(6.11
|
)
|
(a) Amount represents the out-of-period portion of the valuation allowance reversal.
The following table presents the components of our net derivative losses (gains):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Non-cash derivative losses (gains)
|
$
|
25
|
|
|
$
|
(53
|
)
|
|
$
|
243
|
|
|
$
|
(33
|
)
|
Proceeds from settled derivatives
|
(11
|
)
|
|
(15
|
)
|
|
(86
|
)
|
|
(17
|
)
|
Net derivative losses (gains)
|
$
|
14
|
|
|
$
|
(68
|
)
|
|
$
|
157
|
|
|
$
|
(50
|
)
|
The following table presents the reconciliation of our company-wide general and administrative expenses to adjusted general and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
General and administrative expenses
|
$
|
58
|
|
|
$
|
129
|
|
|
$
|
186
|
|
|
$
|
290
|
|
Severance and early retirement costs
|
(1
|
)
|
|
(62
|
)
|
|
(19
|
)
|
|
(72
|
)
|
Adjusted general and administrative expenses
|
$
|
57
|
|
|
$
|
67
|
|
|
$
|
167
|
|
|
$
|
218
|
|
Our results of operations can include the effects of non-cash, unusual and infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore, management uses measures called adjusted net loss and adjusted general and administrative expenses, both of which exclude those items. These measures are not meant to disassociate items from management's performance, but rather are meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net loss and adjusted general and administrative expenses are not considered to be an alternative to net loss or general and administrative expenses, respectively, reported in accordance with United States generally accepted accounting principles (GAAP).
The following table sets forth the average realized prices for our products:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Oil prices with hedge ($ per Bbl)
|
$
|
43.03
|
|
|
$
|
47.79
|
|
|
$
|
40.91
|
|
|
$
|
50.28
|
|
|
|
|
|
|
|
|
|
Oil prices without hedge ($ per Bbl)
|
$
|
41.73
|
|
|
$
|
46.10
|
|
|
$
|
37.54
|
|
|
$
|
49.70
|
|
NGLs prices ($ per Bbl)
|
$
|
22.45
|
|
|
$
|
16.92
|
|
|
$
|
20.36
|
|
|
$
|
19.64
|
|
Gas prices ($ per Mcf)
|
$
|
2.64
|
|
|
$
|
2.83
|
|
|
$
|
2.11
|
|
|
$
|
2.72
|
|
The following table presents our average realized prices as a percentage of Brent, WTI and NYMEX for the three- and six-month periods ended
September 30, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Oil with hedge as a percentage of Brent
|
92
|
%
|
|
93
|
%
|
|
95
|
%
|
|
89
|
%
|
|
|
|
|
|
|
|
|
Oil without hedge as a percentage of Brent
|
89
|
%
|
|
90
|
%
|
|
87
|
%
|
|
88
|
%
|
Oil without hedge as a percentage of WTI
|
93
|
%
|
|
99
|
%
|
|
91
|
%
|
|
97
|
%
|
Gas with hedge as a percentage of NYMEX
|
98
|
%
|
|
102
|
%
|
|
94
|
%
|
|
95
|
%
|
The following table sets forth our average production volumes of oil, NGLs and natural gas per day for the three- and nine-month periods ended
September 30, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Oil (MBbl/d)
|
|
|
|
|
|
|
|
San Joaquin Basin
|
56
|
|
|
64
|
|
|
58
|
|
|
65
|
|
Los Angeles Basin
|
29
|
|
|
32
|
|
|
30
|
|
|
33
|
|
Ventura Basin
|
5
|
|
|
7
|
|
|
5
|
|
|
7
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
90
|
|
|
103
|
|
|
93
|
|
|
105
|
|
|
|
|
|
|
|
|
|
NGLs (MBbl/d)
|
|
|
|
|
|
|
|
San Joaquin Basin
|
15
|
|
|
17
|
|
|
15
|
|
|
17
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
16
|
|
|
18
|
|
|
16
|
|
|
18
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d)
|
|
|
|
|
|
|
|
San Joaquin Basin
|
149
|
|
|
172
|
|
|
150
|
|
|
175
|
|
Los Angeles Basin
|
2
|
|
|
1
|
|
|
3
|
|
|
3
|
|
Ventura Basin
|
8
|
|
|
11
|
|
|
8
|
|
|
11
|
|
Sacramento Basin
|
34
|
|
|
42
|
|
|
36
|
|
|
45
|
|
Total
|
193
|
|
|
226
|
|
|
197
|
|
|
234
|
|
|
|
|
|
|
|
|
|
Total Production (MBoe/d)
(a)
|
138
|
|
|
158
|
|
|
142
|
|
|
161
|
|
_______________________
|
|
Note:
|
MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent per day.
|
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, for the
nine
months ended
September 30, 2016
, the average prices of Brent oil and NYMEX natural gas were
$43.01
per barrel and
$2.24
per Mcf, respectively, resulting in an oil-to-gas ratio of approximately
19
to 1.
|
Balance Sheet Analysis
The changes in our balance sheet from
December 31, 2015
to
September 30, 2016
are discussed below:
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
(in millions)
|
|
|
|
|
Cash and cash equivalents
|
$
|
10
|
|
|
$
|
12
|
|
Trade receivables, net
|
$
|
202
|
|
|
$
|
200
|
|
Inventories
|
$
|
61
|
|
|
$
|
58
|
|
Other current assets
|
$
|
83
|
|
|
$
|
168
|
|
Property, plant and equipment, net
|
$
|
5,953
|
|
|
$
|
6,312
|
|
Other assets
|
$
|
23
|
|
|
$
|
303
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
$
|
74
|
|
|
$
|
100
|
|
Accounts payable
|
$
|
205
|
|
|
$
|
257
|
|
Accrued liabilities
|
$
|
379
|
|
|
$
|
222
|
|
Current income taxes
|
$
|
—
|
|
|
$
|
26
|
|
Long-term debt - principal amount
|
$
|
5,173
|
|
|
$
|
6,043
|
|
Deferred gain and issuance costs, net
|
$
|
410
|
|
|
$
|
491
|
|
Other long-term liabilities
|
$
|
584
|
|
|
$
|
830
|
|
Equity
|
$
|
(493
|
)
|
|
$
|
(916
|
)
|
See "Liquidity and Capital Resources" for further discussion of changes in our cash and cash equivalents and long-term debt, net.
The decrease in other current assets was mainly due to a reduction in the value of our derivative assets. The decrease in property, plant and equipment reflected depreciation, depletion and amortization (DD&A) for the period, partially offset by capital investments. The decrease in other assets was mainly due to increased valuation allowances on deferred tax assets.
The decrease in current maturities of long-term debt was due to the prepayments on our existing term loan during 2016. The decrease in accounts payable reflected lower capital investments and production costs in 2016. The increase in accrued liabilities was primarily due to the deferral of gains related to sales of greenhouse gas allowances, the change in value of derivative liabilities and accrued interest on our debt, partially offset by the effect of severance and employee bonus payments during the first nine months of 2016. Current income taxes and other long-term liabilities as of December 31, 2015 included $336 million in tax liabilities that have subsequently been reclassified to deferred taxes. The other long-term liabilities also reflect higher derivative liabilities due to mark-to-market effects. The decrease in long-term debt reflected the retirement of a portion of our senior unsecured notes and the partial pay down of our bank credit facilities, partially offset by the incurrence of new term loans. The decrease in deferred gain and issuance costs, net, reflected the amortization of deferred gains and new deferred debt issuance costs, partially offset by the amortization and write-off of existing deferred issuance costs. The increase in equity primarily reflected the net income for the nine-month period in 2016.
Statement of Operations Analysis
The following table presents the results of our operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Oil and gas net sales
|
$
|
424
|
|
|
$
|
520
|
|
|
$
|
1,157
|
|
|
$
|
1,687
|
|
Net derivative (losses) gains
|
(14
|
)
|
|
68
|
|
|
(157
|
)
|
|
50
|
|
Other revenue
|
46
|
|
|
38
|
|
|
95
|
|
|
100
|
|
Production costs
|
(211
|
)
|
|
(246
|
)
|
|
(583
|
)
|
|
(730
|
)
|
General and administrative expenses
|
(58
|
)
|
|
(129
|
)
|
|
(186
|
)
|
|
(290
|
)
|
Depreciation, depletion and amortization
|
(137
|
)
|
|
(253
|
)
|
|
(422
|
)
|
|
(757
|
)
|
Taxes other than on income
|
(37
|
)
|
|
(42
|
)
|
|
(118
|
)
|
|
(150
|
)
|
Exploration expense
|
(3
|
)
|
|
(5
|
)
|
|
(13
|
)
|
|
(29
|
)
|
Interest and debt expense, net
|
(95
|
)
|
|
(82
|
)
|
|
(243
|
)
|
|
(244
|
)
|
Other expenses, net
|
(29
|
)
|
|
(23
|
)
|
|
(45
|
)
|
|
(74
|
)
|
Net gain on early extinguishment of debt
|
660
|
|
|
—
|
|
|
793
|
|
|
—
|
|
Income tax benefit
|
—
|
|
|
50
|
|
|
78
|
|
|
165
|
|
Net income (loss)
|
$
|
546
|
|
|
$
|
(104
|
)
|
|
$
|
356
|
|
|
$
|
(272
|
)
|
|
|
|
|
|
|
|
|
Adjusted net income (loss)
(a)
|
$
|
(71
|
)
|
|
$
|
(86
|
)
|
|
$
|
(243
|
)
|
|
$
|
(234
|
)
|
Adjusted EBITDAX
(b)
|
$
|
164
|
|
|
$
|
212
|
|
|
$
|
448
|
|
|
$
|
680
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
—
|
%
|
|
32
|
%
|
|
(28
|
)%
|
|
38
|
%
|
________________________
|
|
(a)
|
See "Financial and Operating Results" above for our Non-GAAP reconciliation.
|
|
|
(b)
|
We define adjusted EBITDAX consistent with our first lien, first out credit facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other non-cash, unusual and infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows, and it is widely used by the industry and investment community. The amounts included in the calculation of adjusted EBITDAX were computed in accordance with GAAP. This measure is a material component of our financial covenants under our first lien, first out credit facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
|
The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted EBITDAX:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Net income (loss)
|
$
|
546
|
|
|
$
|
(104
|
)
|
|
$
|
356
|
|
|
$
|
(272
|
)
|
Interest and debt expense
|
95
|
|
|
82
|
|
|
243
|
|
|
244
|
|
Income tax benefit
|
—
|
|
|
(50
|
)
|
|
(78
|
)
|
|
(165
|
)
|
Depreciation, depletion and amortization
|
137
|
|
|
253
|
|
|
422
|
|
|
757
|
|
Exploration expense
|
3
|
|
|
5
|
|
|
13
|
|
|
29
|
|
Adjusted income items before interest and taxes
(a)
|
(629
|
)
|
|
12
|
|
|
(548
|
)
|
|
45
|
|
Other non-cash items
|
12
|
|
|
14
|
|
|
40
|
|
|
42
|
|
Adjusted EBITDAX
|
$
|
164
|
|
|
$
|
212
|
|
|
$
|
448
|
|
|
$
|
680
|
|
|
|
(a)
|
See "Financial and Operating Results" for a table reconciling net income (loss) to adjusted net income (loss).
|
The following presents costs included in our oil and gas operations, excluding certain corporate items, on a per Boe basis for the
three and nine
months ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Production costs
|
$
|
16.63
|
|
|
$
|
16.91
|
|
|
$
|
15.01
|
|
|
$
|
16.56
|
|
General and administrative expenses
|
$
|
0.63
|
|
|
$
|
1.10
|
|
|
$
|
0.69
|
|
|
$
|
1.00
|
|
Depreciation, depletion and amortization
|
$
|
10.15
|
|
|
$
|
16.92
|
|
|
$
|
10.24
|
|
|
$
|
16.71
|
|
Taxes other than on income
|
$
|
2.44
|
|
|
$
|
2.50
|
|
|
$
|
2.63
|
|
|
$
|
3.02
|
|
Three months ended September 30, 2016
vs.
2015
Oil and gas net sales decreased
18%
, or
$96 million
, for the three months ended
September 30, 2016
, compared to the same period of
2015
, due to reductions of approximately $41 million and $50 million from lower oil prices and volumes, respectively; $3 million and $8 million from lower natural gas prices and volumes, respectively; and an increase of $9 million from higher NGL prices. The lower realized oil prices reflected a significant decrease in global oil prices. Our realized oil prices in 2016 and 2015 also included $11 million and $15 million of cash generated from our hedging program, respectively. Daily oil and gas production volumes averaged
138,000
Boe in the
third
quarter of 2016, compared with
158,000
Boe in the
third
quarter of
2015
, representing a
13%
year-over-year decline rate, consistent with our estimated overall annual base decline rate. The decrease includes PSC effects offset by production deferred from the second quarter of 2016 to the third quarter due to third-party pipeline disruptions. Average oil production decreased by
13%
, or
13,000
barrels per day, to
90,000
barrels per day in the three months ended
September 30, 2016
, compared to the same period of the prior year. NGL production decreased by
11%
to
16,000
barrels per day. Natural gas production decreased by
15%
to
193
MMcf per day, consistent with our focus on liquids. The overall
third
-quarter production decline continued to reflect our decision to withhold development capital and selectively defer workover and downhole maintenance activity in the early part of the year. Due to the improved commodity price environment, we began increasing our activity levels gradually towards the end of the second quarter resulting in lower third-quarter decline rates on a quarter-over-quarter basis. The higher activity levels began contributing to production more meaningfully towards the end of the third quarter.
Derivative losses were $14 million for the three months ended
September 30, 2016
, compared to gains of $68 million in the comparable period of 2015. The change was largely due to volume and valuation changes in our outstanding derivative positions, partially offset by cash settlements.
Production costs for the three months ended
September 30, 2016
decreased $
35 million
, to
$211 million
or $
16.63
per Boe, compared to
$246 million
or $
16.91
per Boe for the same period of
2015
, resulting in a
14%
decrease on an absolute dollar basis. The year-over-year decrease was driven by cost reductions across nearly all of our operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, which also reduced the cost of electricity. However, the increasing workover and downhole maintenance activity combined with higher gas and seasonal energy prices resulted in higher production costs for the third quarter 2016 compared to the prior-year quarter.
Our general and administrative expenses were lower for the three months ended
September 30, 2016
, compared to the same period of
2015
, on a total dollar and per Boe basis, reflecting continued employee and contractor cost-reduction initiatives. The three months ended September 30, 2016 and 2015 included severance and early retirement costs of $1 million and $62 million, respectively. The non-cash portion of general and administrative expenses, comprising equity compensation and a portion of pension costs, was approximately $6 million and $7 million for the three months ended
September 30, 2016
and 2015, respectively.
DD&A expense decreased
46%
, or $
116 million
, for the three months ended
September 30, 2016
, compared to the same period of
2015
. Of this decrease, approximately $98 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2015, and approximately $18 million was attributable to lower volumes.
Taxes other than on income, which include ad valorem taxes, greenhouse gas emissions costs and production taxes, decreased for the three months ended
September 30, 2016
, compared to the same period of
2015
, largely reflecting lower property taxes assessed in the lower price environment.
Exploration expense decreased
40%
, or
$2 million
, for the three months ended
September 30, 2016
, compared to the same period of
2015
, primarily due to reduced exploration activity.
Interest and debt expense, net, increased to
$95 million
for the three months ended
September 30, 2016
, compared to
$82 million
in the same period of 2015, due to higher interest rates, increased amortization of deferred financing costs and a $12 million write-off of the deferred financing costs associated with the tender for our notes during the third quarter of 2016. The increases were partially offset by the amortization of the gain on our fourth quarter 2015 debt exchange and lower debt balances.
Net gain on early extinguishment of debt primarily consisted of the gains on the tender for our notes, net of related expenses.
For the three months ended
September 30, 2016
, while we had pre-tax income of
$546 million
, we had no income tax expense because we expect a tax loss for 2016 for which no tax benefit has been recognized during the three-month period. For the same period of
2015
, we had a benefit of
$50 million
and a pre-tax loss of
$154 million
.
Nine months ended September 30, 2016
vs.
2015
Oil and gas net sales decreased
31%
, or
$530 million
, for the
nine
months ended
September 30, 2016
, compared to the same period of
2015
, due to reductions of approximately $346 million and $121 million from lower oil prices and volumes, respectively; $39 million and $20 million from lower natural gas prices and volumes, respectively; and $7 million from lower NGL volumes. The lower realized oil prices reflected a significant decrease in global oil prices. Our realized prices in 2016 and 2015 also included $86 million and $17 million of cash generated from our hedging program, respectively. Daily oil and gas production volumes averaged
142,000
Boe in the nine months ended
September 30, 2016
, compared with
161,000
Boe in the same period of
2015
representing a
12%
year-over-year decline rate. Average oil production decreased by
11%
or
12,000
barrels per day to
93,000
barrels per day in the first
nine
months ended
September 30, 2016
, compared to the same period of the prior year. NGL production decreased by
11%
to
16,000
barrels per day. Natural gas production decreased by
16%
to
197
MMcf per day, consistent with our focus on liquids.
Derivative losses were $157 million for the nine months ended
September 30, 2016
, compared to gains of $50 million in the comparable period of 2015. The change was largely due to volume and valuation changes in our outstanding derivative positions, partially offset by cash settlements.
Production costs for the
nine
months ended
September 30, 2016
decreased by
$147 million
to
$583 million
or
$15.01
per Boe, compared to
$730 million
or
$16.56
per Boe for the same period of
2015
, resulting in a
20%
decrease on an absolute dollar basis. The decrease was driven by cost reductions across nearly all of our operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, as well as management's decision to increase economic thresholds for capital investment and selectively defer lower value workovers and downhole maintenance activity during the early part of the 2016.
Our general and administrative expenses were lower for the
nine
months ended
September 30, 2016
, compared to the same period of
2015
, on a total dollar and per Boe basis, reflecting continued employee and contractor cost-reduction initiatives. The
nine
months ended September 30, 2016 and 2015 included severance and early retirement costs of $19 million and $72 million, respectively. The non-cash portion of general and administrative expenses, comprising equity compensation and a portion of pension costs, was approximately $20 million and $25 million for the
nine
months ended
September 30, 2016
and 2015, respectively.
DD&A expense decreased
44%
, or
$335 million
, for the
nine
months ended
September 30, 2016
, compared to the same period of
2015
. Of this decrease, approximately $281 million was due to a decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of 2015, and approximately $54 million was attributable to lower volumes.
Taxes other than on income decreased for the
nine
months ended
September 30, 2016
, compared to the same period of
2015
, reflected lower property taxes assessed in the lower price environment prevailing during the period.
Exploration expense decreased
55%
, or
$16 million
, for the
nine
months ended
September 30, 2016
, compared to the same period of
2015
, due to reduced exploration activity and lease rates.
Interest and debt expense, net, of
$243 million
for the
nine
months ended 2016, compared to
$244 million
in the same period of 2015, reflected the higher interest rates, increased amortization of deferred financing costs and a $12 million write-off of the deferred financing costs associated with the tender for our notes during the third quarter of 2016. Offsetting these effects were the amortization of the gain on our fourth quarter 2015 debt exchange and lower debt balances.
Other expenses for the
nine
months ended
September 30, 2016
included the $31 million gain on non-core asset divestitures. Otherwise, the other expenses between the two periods were comparable.
Net gain on early extinguishment of debt for the
nine
months ended
September 30, 2016
resulted from the tender for our notes as well as other note retirements, net of related expenses.
For the
nine
months ended
September 30, 2016
, we had an income tax benefit of
$78 million
reflecting a change in the valuation allowance on our deferred tax assets. While we had pre-tax income of
$278 million
for the period, we had no income tax expense during the first nine months of 2016 because we expect a tax loss for 2016 for which no tax benefit has been recognized during the first nine months of 2016. For the same period of
2015
, we had a benefit of
$165 million
and a pre-tax loss of
$437 million
.
Liquidity and Capital Resources
The primary source of liquidity and capital resources to fund our capital program and other obligations has been cash flow from operations. Operating cash flows are largely dependent on oil and natural gas prices, sales volumes and costs. Average oil prices continued the decline that began in the last half of 2014 into the first quarter of 2016. While global oil prices improved modestly through the third quarter of 2016 and started to trade in a narrower range, they were still lower in the three and nine months ended September 30, 2016 compared to the same periods in 2015. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, and sustained low oil and natural gas prices could continue to have a material and adverse effect on our liquidity position.
Much of the global exploration and production industry is challenged at current price levels, putting pressure on the industry's ability to generate positive cash flow and access capital. If commodity prices were to prevail through the year at about current levels, we would not anticipate a draw down on our revolving credit facility for our annual cash needs, including our current capital program. Our ability to borrow under our revolving credit facility is limited by the size of the facility, by our ability to comply with its covenants, including quarterly financial covenants, and by our borrowing base. Effective November 1, 2016, the borrowing base under our existing first lien first out credit facility was reaffirmed at $2.3 billion. As of September 30, 2016, we had approximately $506 million of available borrowing capacity under our revolving credit facility.
If product prices increase at the rate currently projected in the forward strip and we maintain a cost structure similar to current levels, we expect to be able to comply with our senior bank credit facility covenants through the end of the first quarter of 2018 and possibly beyond. If we were to breach any of our covenants, our lenders would be permitted to accelerate or cross-accelerate the principal amount due under our credit facilities and foreclose on the assets securing them. If payment were accelerated under our credit facilities, it would result in a default under our outstanding notes and permit acceleration and foreclosure on the assets securing our secured notes.
At the beginning of the year, in response to commodity price declines, we budgeted $50 million for our 2016 capital program, compared to our 2015 capital investments of $401 million. In the first half of the year, we further reduced the pace of our capital program to below our initial budget. Since then and in response to recent commodity price improvements, we have modestly increased our planned 2016 capital investments to approximately $75 million to $80 million. Our slowdown of drilling activity from late 2015 through the first half of 2016, coupled with the selective deferral of expense and capital workover activity, led to a decline in production in 2016. However, we began increasing activity levels gradually towards the end of the second quarter, continuing into the third quarter. We started experiencing the positive impact of the increased activity towards the end of the third quarter, and expect to see further production benefit in the fourth quarter which should reduce the base production decline rate. We believe our overall annual base decline rate ranges from 10% to 15%. We cannot guarantee our planned increase in investments will result in a rapid reversal of, or a significant increase in, production trends. Over the long term, if commodity prices fall again or remain at depressed levels, we may experience continued declines in our production and reserves, which could reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations, the value of our assets and our borrowing base.
We focus on creating value and are committed to internally fund our capital budget with operating cash flows. Our low decline assets plus our high level of operational control and absence of significant long-term drilling commitments give us the flexibility to adjust the level of such capital investments as circumstances warrant. We create dynamic budgets that can be adjusted to align investments with projected cash flows. In the event of improved and more consistent prices and cash flow, we may choose to deploy additional capital based on our Value Creation Index (VCI) investment metric, while abiding by our financial covenants.
We have taken a number of other steps to better align our cost structure with the current price environment including a reduction of our workforce to below 1,500 employees as of September 2016. As a result of these steps, in 2016, we have seen a reduction in our production costs and general and administrative expense below 2015 levels. These measures have helped offset some of the cash flow effects of prolonged low commodity prices.
In January and February 2016, we repurchased over $100 million in aggregate principal amount of the senior unsecured notes for under $13 million in cash. In May 2016, we entered into privately negotiated exchange agreements with a holder of our 6% Senior Notes due 2024 and our 5 ½% Senior Notes due 2021 to exchange a total of approximately 2.1 million shares of our common stock on a post-split basis for notes in the aggregate principal amount of $80 million. In August 2016, we issued a new $1 billion first lien, second out term loan credit facility (2016 Second Out Credit Agreement) to prepay a portion of our existing term loans and reduce outstanding revolving loans under our first lien, first out credit facility (2014 First Out Credit Facilities). In October 2016, we entered into privately negotiated exchange agreements with certain holders of our 6% Senior Notes due 2024 and 5 1/2% Senior Notes due 2021 to exchange a total of 1.3 million shares of our common stock for notes in the aggregate principal amount of $23 million.
Given the state of the commodity markets, we will continue to evaluate opportunities to strengthen our balance sheet to competitively position the company for the longer term. As a result, we may from time to time seek to further reduce our outstanding debt using cash from asset sales or other monetizations, exchanging debt for other debt or equity securities or engaging in joint ventures and other activities. Such activities, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our credit facilities, perceived credit risk by counterparties and other factors. The amounts involved may be material. However, we can give no assurances that any of these efforts will be successful or adequately strengthen our balance sheet.
Our strategy for protecting our cash flows and liquidity also includes our hedging program. We currently have the following Brent-based crude oil and PG&E City Gate-based gas hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2016
|
|
FY 2017
|
|
FY 2018
|
Crude Oil
|
|
|
|
|
|
Calls:
|
|
|
|
|
|
Barrels per day
|
25,000
|
|
|
15,500
|
|
|
21,500
|
|
Weighted-average price per barrel
|
$
|
53.62
|
|
|
$
|
54.17
|
|
|
$
|
58.21
|
|
|
|
|
|
|
|
Puts:
|
|
|
|
|
|
Barrels per day
|
3,000
|
|
|
14,300
|
|
|
—
|
|
Weighted-average price per barrel
|
$
|
50.00
|
|
|
$
|
48.60
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Swaps:
|
|
|
|
|
|
Barrels per day
|
39,000
|
|
|
20,000
|
|
|
—
|
|
Weighted-average price per barrel
|
$
|
49.71
|
|
|
$
|
53.98
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
Swaps:
|
|
|
|
|
|
MMBTU per day
|
3,800
|
|
|
—
|
|
|
—
|
|
Weighted-average price per MMBTU
|
$
|
3.49
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Forward Contracts:
|
|
|
|
|
|
MMBTU per day
|
—
|
|
|
4,700
|
|
|
—
|
|
Weighted-average price per MMBTU
|
$
|
—
|
|
|
$
|
3.53
|
|
|
$
|
—
|
|
Certain of our 2017 crude oil swaps grant our counterparty a quarterly option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46.
Credit Facilities
The 2014 First Out Credit Facilities comprise a (i)
$671 million
senior term loan facility (the Term Loan Facility) and (ii) $1.4 billion senior revolving loan facility (the Revolving Credit Facility). We are permitted to increase the size of the Revolving Credit Facility by up to $250 million if we obtain additional commitments from new or existing lenders. The facility matures at the earlier of November 2019 and the 182nd day prior to the maturity of our 5% senior unsecured notes due January 15, 2020 (the 2020 notes), to the extent more than $100 million of such notes remain outstanding at such date. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit.
As of February 2016, we amended the 2014 First Out Credit Facilities to change certain of our financial and other covenants. We again amended this agreement in April 2016 to facilitate certain types of deleveraging transactions and in August 2016 to further change certain of our covenants, grant additional collateral to our lenders and permit the incurrence of debt under the 2016 Second Out Credit Agreement. Borrowings under the 2014 First Out Credit Facility are subject to a borrowing base that was reaffirmed at $2.3 billion as of November 1, 2016. We have granted the lenders under the 2014 First Out Credit Facilities a first-priority lien in a substantial majority of our assets, including our Elk Hills power plant and midstream assets. We also granted a lien in the same assets to the lenders under our 2016 Second Out Credit Agreement and the holders of our senior second lien secured notes due in 2022.
As of September 30, 2016 and December 31, 2015, we had outstanding borrowings under our Revolving Credit Facility of
$772 million
and $739 million, respectively, and outstanding borrowings of $671 million and $1 billion under the Term Loan Facility, respectively. We made scheduled quarterly payments on the Term Loan Facility during the quarters ended March 31, 2016, June 30, 2016 and September 30, 2016, an $11 million prepayment from the proceeds of non-core asset sales in the quarter ended June 30, 2016 and a $250 million prepayment from proceeds of the 2016 Second Out Credit Agreement.
Borrowings under the 2014 First Out Credit Facilities bear interest, at our election, at either a LIBOR rate or an alternate base rate (ABR) (equal to the greatest of (i) the administrative agent’s prime rate, (ii) the one-month LIBOR rate plus 1.00% and (iii) the federal funds effective rate plus 0.50%), in each case plus an applicable margin. This applicable margin is based, while our total leverage ratio exceeds 3.00:1.00, on our borrowing base utilization and will vary from (a) in the case of LIBOR loans, 2.50% to 3.50% and (b) in the case of ABR loans, 1.50% to 2.50%. The unused portion of the Revolving Credit Facility commitments, as limited by the borrowing base, is subject to a commitment fee equal to 0.50% per annum. We also pay customary fees and expenses under the 2014 First Out Credit Facilities. Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly.
Our financial performance covenants under the 2014 First Out Credit Facilities require that (i) the ratio of our first priority, first out secured debt to trailing four quarter EBITDAX (the First-Lien First-Out Leverage Ratio) not exceed 3.50 to 1.00 at any quarter end through the quarter ending June 30, 2017 and 3.25 to 1.00 for the quarters ending September 30 and December 31, 2017 and (ii) the total interest expense coverage ratio at each quarter end not be less than 1.20 to 1.00 at any quarter end through the quarter ending December 31, 2017. Starting with the end of the first quarter of 2018, the First-Lien First-Out Leverage Ratio may not exceed 2.25 to 1.00 and the total interest expense coverage ratio may not be less than 2.00 to 1.00. The covenants also include a new first-lien asset coverage ratio of 1.20 to 1.00 as of any June 30 and December 31 beginning December 31, 2016, which is consistent with a covenant included in the 2016 Second Out Credit Agreement described below.
Our 2014 First Out Credit Facilities require us to apply 100% of the proceeds from asset sales to repay loans outstanding under the 2014 First Out Credit Facilities, except that we are permitted to use up to 40% (or, if our leverage ratio is less than 4:00 to 1:00, 60%) of proceeds from non-borrowing base asset monetizations to repurchase our notes to the extent available at a significant minimum discount to par, as specified in the 2014 First Out Credit Facilities. The 2014 First Out Credit Facilities also permit us to incur up to an additional $50 million, which may be secured by non-borrowing base assets, subject to compliance with our financial covenants and indentures; the proceeds of which must be applied to repay the Term Loan Facility. We must apply cash on hand in excess of $150 million daily to repay amounts outstanding under our Revolving Credit Facility. Further, we are restricted from (i) paying dividends or making other distributions to common stockholders and (ii) making capital investments in excess of $125 million during 2016 or in excess of $200 million during 2017 with a carryover of unused 2016 amounts. The amount permitted to be invested can be increased dollar-for-dollar at any time after June 30, 2017 by the lesser of (a) $50 million and (b) the positive difference between (i) a measure of our liquidity as of June 30, 2017 and (ii) the sum of $500 million and net cash proceeds obtained from non-borrowing base asset dispositions.
Our borrowing base under the 2014 First Out Credit Facilities is redetermined each May 1 and November 1. The borrowing base will be based upon a number of factors, including commodity prices and reserves. Increases in our borrowing base require approval of at least 80% of our revolving lenders, as measured by exposure, while decreases or affirmations require a two-thirds approval. We and the lenders (requiring a request from the lenders holding two-thirds of the revolving commitments and outstanding loans) each may request a special redetermination once in any period between three consecutive scheduled redeterminations. We will be permitted to have collateral released when both (i) our credit ratings are at least Baa3 from Moody's and BBB- from S&P, in each case with a stable or better outlook, and (ii) certain permitted liens securing other debt are released.
Substantially all of the restrictions imposed by the February 2016 amendment to the Credit Facilities, other than the requirement for semiannual borrowing base redeterminations, may terminate in the future if we are able to comply with the financial covenants as they existed prior to giving effect to the amendment.
The net borrowings under the 2016 Second Out Credit Agreement were used to (i) prepay $250 million of the Term Loan Facility and (ii) reduce our Revolving Credit Facility by $740 million. The proceeds received were net of a $10 million original issue discount. The term loans bear interest at a floating rate per annum equal to 10.375% plus LIBOR, subject to a 1.00% LIBOR floor, determined for the applicable interest period (or ABR rates in certain circumstances). Interest on ABR loans is payable quarterly in arrears. Interest on LIBOR loans is payable at the end of each LIBOR period, but not less than quarterly.
The 2016 Second Out Credit Agreement is secured by a security interest in the same collateral used to secure the 2014 First Out Credit Facilities, but, under intercreditor arrangements with our 2014 First Out Credit Facilities lenders, are second in collateral recovery behind such lenders. Prepayment of the 2016 Second Out Credit Agreement is subject to a make-whole premium prior to the third anniversary of closing and a premium to par equal to 50% of coupon between the third anniversary and the fourth anniversary. Following the fourth anniversary, we may redeem at par. The 2016 Second Out Credit Agreement matures on December 31, 2021, but if the aggregate principal amount outstanding of either our 2020 Notes or our 5½% senior unsecured notes due September 15, 2021 (the 2021 Notes) exceeds $100 million 91 days prior to their respective maturity dates, the maturity date of the term loans will accelerate to such prior 91st day. As of September 30, 2016, we had
$193 million
and
$149 million
in aggregate principal amount of outstanding 2020 notes and 2021 notes, respectively.
The 2016 Second Out Credit Agreement provides for customary covenants and events of default consistent with, or generally less restrictive than, the covenants in our 2014 First Out Credit Facilities, including limitations on additional indebtedness, liens, asset dispositions, investments, restricted payments and other negative covenants, in each case subject to certain limitations and exceptions. Additionally, the 2016 Second Out Credit Agreement requires us to maintain a first-lien asset coverage ratio of 1.20 to 1.00 as of any June 30 and December 31 beginning December 31, 2016, consistent with the 2014 First Out Credit Facilities.
All obligations under the 2014 First Out Credit Facilities and the 2016 Second Out Credit Agreement (Credit Facilities) are guaranteed jointly and severally by all of our material wholly owned subsidiaries. The assets and liabilities of subsidiaries not guaranteeing the debt are de minimis.
At September 30, 2016, we were in compliance with the financial and other covenants under our Credit Facilities.
Senior Notes
In October 2014, we issued $5.00 billion in aggregate principal amount of our senior unsecured notes, including $1.00 billion of 2020 notes, $1.75 billion of 2021 notes and $2.25 billion of 6% senior unsecured notes due November 15, 2024 (the 2024 notes and together with the 2020 notes and the 2021 notes, the unsecured notes). The unsecured notes were issued at par and are fully and unconditionally guaranteed on a senior unsecured basis by all of our material subsidiaries. We used the net proceeds from the issuance of the unsecured notes to make a $4.95 billion cash distribution to Occidental in October 2014.
In December 2015, we exchanged $534 million, $921 million and $1,358 million in aggregate principal amount of the 2020 notes, the 2021 notes, and the 2024 notes, respectively, for $2.25 billion in aggregate principal amount of newly issued 8% senior secured second lien notes due December 15, 2022 (the 2022 notes). We recorded a deferred gain of approximately $560 million on the debt exchange, which will be amortized using the effective interest rate method over the term of the 2022 notes. Additionally, we incurred approximately $28 million in third-party costs which were fully expensed in 2015. Our 2022 notes are secured on a second-priority basis, subject to the terms of an intercreditor agreement and collateral trust agreement, by a lien on the same collateral used to secure our obligations under our Credit Facilities.
During the three months ended March 31, 2016, we repurchased over $100 million in aggregate principal amount of the senior unsecured notes for under $13 million in cash. During the three months ended June 30, 2016, we entered into privately negotiated exchange agreements with a holder of our 6% Senior Notes due 2024 and our 5 ½% Senior Notes due 2021 to exchange a total of approximately 2.1 million shares of our common stock on a post-split basis for notes in the aggregate principal amount of $80 million.
In August 2016, we repurchased $197 million, $605 million and $613 million in aggregate principal amount of our 2020 notes, 2021 notes and 2024 notes, respectively, for $750 million using our Revolving Credit Facility, resulting in a $660 million pre-tax gain, net of related expenses. These repurchases resulted in a net reduction of our debt of $625 million. Additionally, we wrote off approximately $12 million of deferred costs related to the repurchased notes.
In October 2016, we entered into privately negotiated exchange agreements with certain holders of our 6% Senior Notes due 2024 and 5 1/2% Senior Notes due 2021 to exchange a total of 1.3 million shares of our common stock for notes in the aggregate principal amount of $23 million.
We will pay interest semiannually in cash in arrears on January 15 and July 15 for the 2020 notes, on March 15 and September 15 for the 2021 notes, on June 15 and December 15 for the 2022 notes and on May 15 and November 15 for the 2024 notes.
The indentures governing the senior unsecured notes and the second lien secured notes each include covenants that, among other things, limit our and our subsidiaries’ ability to incur debt secured by liens. The indentures also restrict our ability to merge or consolidate with, or transfer all or substantially all of our assets to, another entity. These covenants are subject to a number of important qualifications and limitations that are set forth in the indenture. The covenants are not, however, directly linked to measures of our financial performance. In addition, if we experience a “change of control triggering event” (as defined in the indentures) with respect to a series of notes, we will be required, unless we have exercised our right to redeem the notes of such series, to offer to purchase the notes of such series at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest. The indenture governing our second lien secured notes also restricts our ability to sell certain assets and to release collateral from liens securing the second lien secured notes, unless the collateral is released in compliance with our Credit Facilities.
Other
A one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities on
September 30, 2016
, would result in a
$3 million
change in annual interest expense.
As of
September 30, 2016
and December 31, 2015, we had letters of credit in the aggregate amount of approximately
$127 million
and $70 million (including
$122 million
and $49 million under the Revolving Credit Facility), respectively, which were issued to support ordinary course marketing, insurance, regulatory and other matters.
Cash Flow Analysis
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2016
|
|
2015
|
|
|
(in millions)
|
Net cash flows provided by operating activities
|
|
$
|
145
|
|
|
$
|
412
|
|
Net cash flows used in investing activities
|
|
$
|
(31
|
)
|
|
$
|
(542
|
)
|
Net cash flows (used) provided by financing activities
|
|
$
|
(116
|
)
|
|
$
|
120
|
|
Adjusted EBITDAX
(a)
|
|
$
|
448
|
|
|
$
|
680
|
|
_______________________________
|
|
(a)
|
We define adjusted EBITDAX consistent with our first lien, first out credit facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other non-cash, unusual and infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and it is widely used by the industry and investment community. The amounts included in the calculation of adjusted EBITDAX were computed in accordance with GAAP. This measure is a material component of our financial covenants under our first lien, first out credit facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
|
The following table sets forth a reconciliation of the GAAP measure of net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX:
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2016
|
|
2015
|
|
|
(in millions)
|
Net cash provided by operating activities
|
|
$
|
145
|
|
|
$
|
412
|
|
Cash interest
|
|
244
|
|
|
248
|
|
Exploration expenditures
|
|
13
|
|
|
20
|
|
Other changes in operating assets and liabilities
|
|
32
|
|
|
(6
|
)
|
Plant turnaround, outage and other costs
|
|
14
|
|
|
6
|
|
Adjusted EBITDAX
|
|
$
|
448
|
|
|
$
|
680
|
|
Our net cash provided by operating activities was $
145 million
and
$412 million
for the
nine
months ended
September 30, 2016
and
2015
, respectively. The first nine months of 2016, as compared with the same period in 2015, reflected lower revenues of $466 million, primarily due to lower commodity prices and volumes, net of cash
generated from our hedging program, partially offset by lower production costs of $147 million, the cash portion of general and administrative expenses of $46 million and taxes other than on income of $32 million as well as the negative effect of working capital changes.
Our net cash flow used by investing activities decreased
$511 million
for the
nine
months ended
September 30, 2016
, compared to the same period of
2015
, primarily due to significantly lower capital investments and lower payments related to capital activity from prior periods.
Our net cash flow used by financing activities of
$116 million
for the
nine
months ended
September 30, 2016
included approximately $33 million in net proceeds from the Revolving Credit Facility, $329 million in payments on the Term Loan Facility and $814 million in debt repurchases and other costs. Our net cash flow provided by financing activities of
$120 million
for the
nine
months ended September 30, 2015 included approximately $121 million in net proceeds on the Revolving Credit Facility.
2016 Capital Program
At the beginning of the year, we budgeted $50 million for our 2016 capital program, primarily to maintain the mechanical integrity of our facilities and systems and operate them safely. In the first half of the year, we further reduced the pace of our capital program to below our initial budget. Since then and in response to recent commodity price improvements, we have modestly increased our planned 2016 capital investments to approximately $75 million to $80 million. Our slowdown of drilling activity from late 2015 through the first half of 2016, coupled with the selective deferral of expense and capital workover activity, led to a decline in production in 2016. However, we began increasing activity levels gradually towards the end of the second quarter, continuing in to the third quarter. We started experiencing the positive impact of the increased capital activity towards the end of the third quarter, and expect to see further production benefit in the fourth quarter which should reduce the base production decline rate. We believe our overall annual base decline rate ranges from 10% to 15%. We cannot guarantee our planned increase in investments will result in a rapid reversal of, or a significant increase in, production trends. Over the long term, if commodity prices fall again or remain at depressed levels, we may experience continued declines in our production and reserves, which could reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations, the value of our assets and our borrowing base.
We focus on creating value and are committed to internally fund our capital budget with operating cash flows. Our low decline assets plus our high level of operational control and absence of significant long-term drilling commitments give us the flexibility to adjust the level of such capital investments as circumstances warrant. We create dynamic budgets that can be adjusted to align investments with projected cash flows. In the event of improved and more consistent prices and cash flow, we may choose to deploy additional capital based on our VCI investment metric, while abiding by our financial covenants.
Lawsuits, Claims, Contingencies and Commitments
We, or certain of our subsidiaries, are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.
On April 21, 2016, a purported class action was filed against us in the United States District Court for the Southern District of New York on behalf of all beneficial owners of our unsecured notes from November 12, 2015 to the present. The complaint alleges that our December 2015 debt exchange excluded non-qualified institutional holders in violation of the Trust Indenture Act of 1939 and related law and, thereby, impaired their rights to receive principal and interest payments. The purported class action seeks declaratory relief that the debt exchange and the liens securing the new notes are null and void and that the debt exchange resulted in a default. The plaintiff also seeks monetary damages and attorneys’ fees. We plan to vigorously defend against the claims made by the plaintiff.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserves balances at
September 30, 2016
and
December 31, 2015
were not material to our balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.
We, our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with the Spin-off, purchases and other transactions that they have entered into with us. These indemnities include indemnities made to Occidental against certain tax-related liabilities that may be incurred by Occidental relating to the Spin-off and liabilities related to operation of our business while it was still owned by Occidental. As of
September 30, 2016
, we are not aware of material indemnity claims pending or threatened against us.
We were contacted by the Internal Revenue Service for examination of our U.S. federal income tax return for the one month ended December 2014. Subsequent taxable years and state returns remain subject to examination.
Significant Accounting and Disclosure Changes
In August 2016, the Financial Accounting Standards Board (FASB) issued rules that modify how certain cash receipts and cash payments are presented and classified in the statement of cash flows. These rules are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, with earlier adoption permitted. We are currently evaluating the impact of these rules on our financial statements.
In June 2016, the FASB issued rules that change how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value. These rules are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of these rules on our financial statements.
In April 2016, the FASB issued rules requiring that entities recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, in March 2016, the FASB issued rules intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations and whether an entity reports revenue on a gross or net basis. These rules have the same effective date, generally in the first interim period of fiscal year 2018, as the related revenue standard issued in 2014. We are currently evaluating the impact of these rules on our financial statements.
In February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. These rules will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with earlier application permitted. We are currently evaluating the impact of these rules on our financial statements.
In January 2016, the FASB issued rules that modify how entities measure equity investments and present changes in the fair value of financial liabilities. Unless the investments qualify for a practicality exception, the new rules require all equity investments to be measured at fair value with changes in the fair value recognized through net income (other than those accounted for under the equity method of accounting or those that result in consolidation of the investee). Entities will have to record changes in instrument-specific credit risk for financial liabilities measured under the fair value option in other comprehensive income. These new rules become effective for fiscal years beginning after December 15, 2017 with no early adoption permitted. We are currently evaluating the impact of these rules, but we do not expect them to have a significant impact on our financial statements.
Safe Harbor Statement Regarding Outlook and Forward-Looking Information
The information in this document includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business prospects, budgets, drilling and workover program, maintenance capital, projected production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect our results of operations and financial position appear in Part I, Item 1A, Risk Factors of the 2015 Form 10-K.
Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency of our operating cash flow to fund planned capital expenditures; steeper than expected production decline rates; inability to implement our capital investment program; inability to replace reserves; inability to obtain government permits and approvals; inability to monetize selected assets; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; risks related to our disposition and acquisition activities; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; the recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; the effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the Spin-off and the agreements related thereto. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.
All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.