CALGARY, AB – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today announced financial and operating results for the first quarter of 2022, along with an increase to its return of capital plans, and updated guidance. The Company reported first quarter 2022 cash flow from operating activities and adjusted funds flow(1) of $196.0 million and $261.9 million, respectively, compared to $28.7 million and $100.9 million, respectively, in the first quarter of 2021. Cash flow from operating activities and adjusted funds flow increased from the prior year period primarily due to improved realized commodity prices and higher production.
HIGHLIGHTS
- Adjusted funds flow(1) was $262 million in the first quarter, which exceeded capital spending of $99 million, generating free cash flow(1) of $163 million
- Estimated 2022 free cash flow(1) is $675 million based on rest of year prices of $85 WTI and $5.00 NYMEX
- Increasing total 2022 cash returns to shareholders to a minimum of $350 million or 50% of annual free cash flow, whichever is greater, through dividends and share repurchases
- Increased quarterly dividend by 30% to $0.043 per share
- Production guidance for 2022 increased to 96,000 – 101,000 BOE per day (from 95,500 – 100,500 BOE per day) due to strong operational execution and optimizations
- Capital spending guidance for 2022 revised to $400 – $440 million (from $370 – $430 million) primarily due to inflationary impacts
- Realized 2022 Bakken oil price expected to be at par with WTI
(1) This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
“Our strong operating performance year to date is continuing to support a robust production outlook,” said Ian C. Dundas, President and CEO. “Enerplus remains well positioned to execute its 2022 plan which is expected to deliver record free cash flow and meaningful cash returns to shareholders.”
“In conjunction with this outlook, we are enhancing our 2022 return of capital plan by committing to a minimum of $350 million or 50% of free cash flow, whichever is greater, returned to shareholders through dividends and share repurchases.”
Dundas continued, “High commodity prices and supply chain tightness are creating inflationary pressures across the industry. We are not immune to these pressures. However, actions we took last year to secure services, equipment and supplies have significantly mitigated the impacts and are enabling us to execute our operating plan efficiently, with no plans to increase activity levels or chase higher, less efficient growth.
FIRST QUARTER SUMMARY
Production in the first quarter of 2022 was 92,196 BOE per day, an increase of 25% compared to the same period a year ago, and 10% lower than the prior quarter. Crude oil and natural gas liquids production in the first quarter of 2022 was 56,011 barrels per day, an increase of 42% compared to the same period a year ago, and 14% lower than the prior quarter. The higher production compared to the same period in 2021 was primarily due to the Company’s 2021 Bakken acquisitions and development program. The lower production compared to the prior quarter was due to the planned sequencing of the Company’s completions program in North Dakota which included a break in onstream activity between early November 2021 through late March 2022, and the divestment of Montana and Russian Creek interests in the fourth quarter of 2021.
Enerplus reported first quarter 2022 net income of $33.2 million, or $0.13 per share (diluted), compared to net income of $10.3 million, or $0.04 per share (diluted), in the same period in 2021. Adjusted net income(1) for the first quarter of 2022 was $145.8 million, or $0.58 per share (diluted), compared to $43.9 million, or $0.18 per share (diluted), during the same period in 2021. Net income and adjusted net income were higher compared to the prior year period primarily due to higher production and benchmark commodity prices and stronger commodity price realizations during the first quarter of 2022.
Enerplus’ first quarter 2022 realized Bakken oil price differential was $0.35 per barrel below WTI, compared to $3.19 per barrel below WTI in the first quarter of 2021. The improved year-over-year Bakken differential was due to an improvement in the supply and demand balance, excess pipeline capacity in the region, and strong prices for crude oil delivered to the U.S. Gulf Coast. Given the constructive outlook for Bakken crude oil prices and strong realizations year to date, Enerplus expects its 2022 realized Bakken oil price to be at par with WTI, compared to $0.50 per barrel below WTI previously.
The Company’s realized Marcellus natural gas price differential was $0.01 per Mcf above NYMEX during the first quarter of 2022, compared to $0.15 per Mcf below NYMEX in the first quarter of 2021. Realized Marcellus differentials are expected to widen for the remainder of the year due to the seasonal impact on natural gas prices in the region. As a result, Enerplus’ full-year 2022 Marcellus differential guidance is unchanged at $0.75 per Mcf below NYMEX.
In the first quarter of 2022, Enerplus’ operating costs were $10.03 per BOE, compared to $7.71 per BOE during the first quarter of 2021. The increase in per unit operating expenses was due to the Company’s higher crude oil weighting in its production mix, contracts with price escalators linked to WTI and the Consumer Price Index, and increased well service activity.
Capital spending totaled $99.0 million in the first quarter of 2022. The Company paid $7.9 million in dividends in the quarter and repurchased 3.1 million shares at an average price of $11.87 per share, for total consideration of $37.2 million. Subsequent to March 31, 2022, and up to and including May 4, 2022, Enerplus repurchased 1.5 million shares at an average price of $12.61 per share, for total consideration of $18.9 million.
Enerplus ended the first quarter of 2022 with total debt of $595.0 million and cash of $22.7 million.
(1) This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
ASSET HIGHLIGHTS
Williston Basin production averaged 57,343 BOE per day during the first quarter of 2022, an increase of 51% compared to the same period a year ago, driven by Enerplus’ 2021 acquisitions and ongoing development. Williston Basin production was 15% lower than the prior quarter due to the planned sequencing of the Company’s completions program which included a break in onstream activity between early November 2021 through late March 2022, and the divestment of Montana and Russian Creek interests in the fourth quarter of 2021. The Company brought two operated wells (100% working interest) on production from a six-well pad at the end of March 2022. The remaining four wells were brought on production subsequent to the quarter-end. Enerplus drilled 14 gross operated wells (12 net) during the first quarter and is continuing to operate two drilling rigs. The second quarter is expected to be Enerplus’ most active operational quarter in 2022 with approximately 18 – 21 net wells projected to be brought on production.
Marcellus production averaged 162 MMcf per day during the first quarter of 2022, approximately flat compared to the same period in 2021 and the prior quarter. Canadian waterflood production averaged 5,495 BOE per day during the first quarter of 2022, approximately flat compared to the same period in 2021, and 4% lower than the prior quarter.
INCREASING RETURN OF CAPITAL TO SHAREHOLDERS
Assuming commodity prices of $85 per barrel WTI and $5.00 per Mcf NYMEX for the rest of 2022, Enerplus expects to generate approximately $675 million of annual free cash flow(1), representing a reinvestment rate(1) of less than 40%. Enerplus remains committed to both returning a significant portion of free cash flow to shareholders and reducing debt.
Enerplus’ board of directors has approved an increase to the Company’s 2022 return of capital plan to a minimum of $350 million or 50% of annual free cash flow, whichever is greater, through dividends and share repurchases.
In connection with this plan, the board has approved a 30% increase to the Company’s quarterly dividend to $0.043 per share payable on June 15, 2022 to shareholders of record on May 27, 2022. The increased dividend is equal to approximately $40 million on an annualized basis.
The remaining $310 million or greater of shareholder returns in 2022 are expected to be delivered via the Company’s share repurchase program, based on current market conditions. Enerplus plans to repurchase its remaining 8.0 million share authorization under its normal course issuer bid (“NCIB”) by the end of July 2022 and renew its NCIB in August 2022 for approximately 10% of the outstanding shares.
Enerplus’ approach to share repurchases continues to be grounded in its assessment that its intrinsic value, based on its mid-cycle commodity price view, is not adequately reflected in its current trading value. If this view changes such that Enerplus believes share repurchases no longer represent an attractive capital allocation opportunity, the Company will distribute the capital to shareholders through dividends to ensure it meets its shareholder returns commitment.
The remaining 50% of 2022 free cash flow not allocated to shareholder returns is expected to be directed to reinforcing the balance sheet.
(1) This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
2022 GUIDANCE UPDATE
Enerplus is revising its capital spending guidance to $400 to $440 million, from $370 to $430 million previously. The updated guidance is a result of inflationary pressures due to the high commodity price environment and supply chain tightness, along with increased non-operated activity and associated costs. On its operated activity in North Dakota, Enerplus currently projects 2022 wells costs will average approximately $6.5 million compared to its initial budget of $6.0 million, with the increase primarily due to higher diesel and steel costs.
In April, severe winter weather in North Dakota temporarily impacted Enerplus’ operations. The Company estimates that it lost approximately 1,000 BOE per day of annual average 2022 production due to the storm impacts. However, through strong operational execution and the continued optimization of the Company’s development plan, Enerplus has more than offset the impact from weather-related downtime to its annual production forecast. As a result, Enerplus is increasing its guidance to 96,000 to 101,000 BOE per day, compared to 95,500 to 100,500 BOE per day previously. Liquids production guidance has been increased to 58,500 to 62,500 barrels per day, compared to 58,000 to 62,000 barrels per day previously.
Given the constructive outlook for Bakken crude oil prices and strong realizations year to date, Enerplus expects its 2022 realized Bakken oil price to be at par with WTI, compared to $0.50 per barrel below WTI previously.
Due to additional costs incurred to restore production following weather-related downtime, Enerplus is increasing the lower end of its operating cost guidance to $9.75 per BOE, from $9.50 per BOE previously.
As a result of the higher commodity price environment, Enerplus is updating its current tax guidance from $10 million to $20 to $30 million (2% – 3% of adjusted funds flow before tax) for 2022 assuming WTI of $85.00 per barrel and NYMEX of $5.00 per Mcf.
2022 Guidance Summary
Updated Guidance | Previous Guidance | |
Capital spending | $400 – 440 million | $370 – 430 million |
Average total production | 96,000 – 101,000 BOE/day | 95,500 – 100,500 BOE/day |
Average liquids production | 58,500 – 62,500 bbls/day | 58,000 – 62,000 bbls/day |
Average production tax rate
(% of net sales, before transportation) |
7% | 7% |
Operating expense | $9.75 – 10.50/BOE | $9.50 – 10.50/BOE |
Transportation expense | $4.15/BOE | $4.15/BOE |
Cash G&A expense | $1.25/BOE | $1.25/BOE |
Current tax expense | $20 – $30 million
(2-3% of adjusted funds flow before tax) |
$10 million |
2022 Differential/Basis Outlook(1)
Updated Guidance | Previous Guidance | |
U.S. Bakken crude oil differential
(compared to WTI crude oil) |
$0/bbl | $(0.50)/bbl |
Marcellus natural gas sales price differential
(compared to NYMEX natural gas) |
$(0.75)/Mcf | $(0.75)/Mcf |
(1) Excluding transportation costs. |
Q1 2022 Conference Call Details
A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) on May 6, 2022 to discuss these results. Details of the conference call are as follows:
Date: | Friday, May 6, 2022 |
Time: | 9:00 AM MT (11:00 AM ET) |
Dial-In: | 587-880-2171 (Alberta) |
1-888-390-0546 (Toll Free) | |
Conference ID: | 14832308 |
Audiocast: | https://produceredition.webcasts.com/starthere.jsp?ei=1542034&tp_key=861128c0b5 |
To ensure timely participation in the conference call, callers are encouraged to join 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:
Replay Dial-In: | 1-888-390-0541 (Toll Free) |
Replay Passcode: | 832308 # |
PRICE RISK MANAGEMENT
The following is a summary of Enerplus’ financial commodity hedging contracts at May 4, 2022.
WTI Crude Oil ($/bbl)(1)(2)(3) |
NYMEX Natural Gas ($/Mcf)(2) |
|||||||||
Apr 1, 2022 – | Apr 1, 2022 – | Jan 1, 2023 – | Jan 1, 2023 – | Apr 1, 2022 – | ||||||
June 30, 2022 | Dec 31, 2022 | June 30, 2023 | Dec 31, 2023 | Oct 31, 2022 | ||||||
Swaps | ||||||||||
Volume (Mcf/day) | – | – | – | – | 40,000 | |||||
Sold Puts | – | – | – | – | $ 3.40 | |||||
Collars | ||||||||||
Volume (Mcf/day) | – | – | – | – | 60,000 | |||||
Volume (bbls/day) | 12,500 | 17,000 | 10,000 | 2,000 | – | |||||
Sold Puts | $ 58.00 | $ 40.00 | $ 60.00 | – | – | |||||
Purchased Puts | $ 75.00 | $ 50.00 | $ 76.50 | $ 5.00 | $ 3.77 | |||||
Sold Calls | $ 87.63 | $ 57.91 | $ 107.38 | $ 75.00 | $ 4.50 |
(1) The total average deferred premium spent on outstanding hedges is $1.50/bbl from April 1, 2022 – December 31, 2022 and $1.25/bbl from January 1, 2023 – June 30, 2023. (2) Transactions with a common term have been aggregated and presented at weighted average prices and volumes. (3) Upon closing of the Bruin acquisition, Bruin’s outstanding crude oil contracts were recorded at a fair value liability of $76.4 million. At March 31, 2022, the balance was a liability of $16.3 million on the Condensed Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Condensed Consolidated Statement of Income/(Loss) and the Condensed Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition. See Note 16 to the Interim Financial Statements for further details. |
FIRST QUARTER 2022 PRODUCTION AND OPERATIONAL SUMMARY TABLES
Summary of Average Daily Production(1)
Three months ended March 31, 2022 | |||||
Williston Basin | Marcellus | Canadian Waterfloods |
Other(2) | Total | |
Tight oil (bbl/d) | 41,554 | – | – | 874 | 42,428 |
Light & medium oil (bbl/d) | – | – | 2,150 | 22 | 2,172 |
Heavy oil (bbl/d) | – | – | 3,027 | 7 | 3,034 |
Total crude oil (bbl/d) | 41,554 | – | 5,177 | 903 | 47,634 |
Natural gas liquids (bbl/d) | 7,979 | – | 88 | 310 | 8,377 |
Shale gas (Mcf/d) | 46,858 | 162,138 | – | 922 | 209,918 |
Conventional natural gas (Mcf/d) | – | – | 1,380 | 5,813 | 7,193 |
Total natural gas (Mcf/d) | 46,858 | 162,138 | 1,380 | 6,735 | 217,111 |
Total production (BOE/d) | 57,343 | 27,023 | 5,495 | 2,335 | 92,196 |
(1) Table may not add due to rounding. (2) Comprises DJ Basin and other properties in Canada. |
Summary of Wells Drilled(1)
Three months ended March 31, 2022 | ||||
Operated | Non-Operated | |||
Gross | Net | Gross | Net | |
Williston Basin | 14 | 12.0 | 12 | 1.5 |
Marcellus | – | – | 16 | 1.4 |
Canadian Waterfloods | – | – | – | – |
Other(2) | – | – | – | – |
Total | 14 | 12.0 | 28 | 2.9 |
(1) Table may not add due to rounding. (2) Comprises DJ Basin and other properties in Canada. |
Summary of Wells Brought On-Stream(1)
Three months ended March 31, 2022 | ||||
Operated | Non-Operated | |||
Gross | Net | Gross | Net | |
Williston Basin | 2 | 2.0 | – | – |
Marcellus | – | – | 25 | 1.5 |
Canadian Waterfloods | – | – | – | – |
Other(2) | – | – | – | – |
Total | 2 | 2.0 | 25 | 1.5 |
(1) Table may not add due to rounding. (2) Comprises DJ Basin and other properties in Canada. |
SELECTED FINANCIAL RESULTS | Three months ended March 31, |
|||||
2022 | 2021 | |||||
Financial (US$, thousands, except ratios) | ||||||
Net Income/(Loss) | $ | 33,243 | $ | 10,349 | ||
Adjusted Net Income/(Loss)(1) | 145,828 | 43,871 | ||||
Cash Flow from Operating Activities | 195,992 | 28,662 | ||||
Adjusted Funds Flow(1) | 261,895 | 100,854 | ||||
Dividends to Shareholders – Declared | 7,918 | 5,634 | ||||
Net Debt | 572,271 | 632,200 | ||||
Capital Spending | 99,013 | 51,818 | ||||
Property and Land Acquisitions | 1,941 | 497,139 | ||||
Property Divestments | 6,581 | 4,010 | ||||
Net Debt to Adjusted Funds Flow Ratio(1) | 0.7x | 2.2x | ||||
Financial per Weighted Average Shares Outstanding | ||||||
Net Income /(Loss) – Basic | $ | 0.14 | $ | 0.04 | ||
Net Income/(Loss) – Diluted | 0.13 | 0.04 | ||||
Weighted Average Number of Shares Outstanding (000’s) – Basic | 242,787 | 244,066 | ||||
Weighted Average Number of Shares Outstanding (000’s) – Diluted | 249,337 | 246,898 | ||||
Selected Financial Results per BOE(2)(3) | ||||||
Crude Oil & Natural Gas Sales(4) | $ | 61.84 | $ | 34.43 | ||
Commodity Derivative Instruments | (8.81) | (2.32) | ||||
Operating Expenses | (10.03) | (7.71) | ||||
Transportation Costs | (4.32) | (3.91) | ||||
Production Taxes | (4.26) | (2.09) | ||||
General and Administrative Expenses | (1.35) | (1.57) | ||||
Cash Share-Based Compensation | (0.25) | (0.32) | ||||
Interest, Foreign Exchange and Other Expenses | (0.66) | (1.31) | ||||
Current Income Tax Recovery/(Expense) | (0.60) | — | ||||
Adjusted Funds Flow(1) | $ | 31.56 | $ | 15.20 |
SELECTED OPERATING RESULTS | Three months ended
March 31, |
|||||
2022 | 2021 | |||||
Average Daily Production(3) | ||||||
Crude Oil (bbls/day) | 47,634 | 34,112 | ||||
Natural Gas Liquids (bbls/day) | 8,377 | 5,270 | ||||
Natural Gas (Mcf/day) | 217,111 | 205,949 | ||||
Total (BOE/day) | 92,196 | 73,707 | ||||
% Crude Oil and Natural Gas Liquids | 61% | 53% | ||||
Average Selling Price(3)(4) | ||||||
Crude Oil (per bbl) | $ | 91.95 | $ | 53.24 | ||
Natural Gas Liquids (per bbl) | 37.78 | 28.55 | ||||
Natural Gas (per Mcf) | 4.62 | 2.76 | ||||
Net Wells Drilled | 15 | 1 |
(1) These non‑GAAP measures may not be directly comparable to similar measures presented by other entities See “Non-GAAP and Other Financial Measures” section in this news release. (2) Non‑cash amounts have been excluded. (3) Based on net production volumes. See “Basis of Presentation” section in this news release. (4) Before transportation costs and commodity derivative instruments. |
Condensed Consolidated Balance Sheets
(US$ thousands) unaudited | March 31, 2022 | December 31, 2021 | ||||
Assets | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | 22,731 | $ | 61,348 | ||
Accounts receivable | 282,644 | 227,988 | ||||
Other current assets | 9,118 | 10,956 | ||||
Derivative financial assets | — | 5,668 | ||||
314,493 | 305,960 | |||||
Property, plant and equipment: | ||||||
Crude oil and natural gas properties (full cost method) | 1,303,239 | 1,253,505 | ||||
Other capital assets | 13,234 | 13,887 | ||||
Property, plant and equipment | 1,316,473 | 1,267,392 | ||||
Other long-term assets | 7,526 | 9,756 | ||||
Right-of-use assets | 24,492 | 26,118 | ||||
Deferred income tax asset | 374,238 | 380,858 | ||||
Total Assets | $ | 2,037,222 | $ | 1,990,084 | ||
Liabilities | ||||||
Current liabilities | ||||||
Accounts payable | $ | 404,192 | $ | 367,008 | ||
Current portion of long-term debt | 100,600 | 100,600 | ||||
Derivative financial liabilities | 257,038 | 143,200 | ||||
Current portion of lease liabilities | 10,852 | 10,618 | ||||
772,682 | 621,426 | |||||
Long-term debt | 494,402 | 601,171 | ||||
Asset retirement obligation | 144,591 | 132,814 | ||||
Derivative financial liabilities | 13,866 | 7,098 | ||||
Lease liabilities | 16,310 | 18,265 | ||||
669,169 | 759,348 | |||||
Total Liabilities | 1,441,851 | 1,380,774 | ||||
Shareholders’ Equity | ||||||
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: March 31, 2022 – 242 million shares December 31, 2021 – 244 million shares |
3,070,678 | 3,094,061 | ||||
Paid-in capital | 36,110 | 50,881 | ||||
Accumulated deficit | (2,218,865) | (2,238,325) | ||||
Accumulated other comprehensive loss | (292,552) | (297,307) | ||||
595,371 | 609,310 | |||||
Total Liabilities & Shareholders’ Equity | $ | 2,037,222 | $ | 1,990,084 | ||
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
Three months ended | ||||||
March 31, | ||||||
(US$ thousands, except per share amounts) unaudited | 2022 | 2021 | ||||
Revenues | ||||||
Crude oil and natural gas sales | $ | 513,152 | $ | 228,390 | ||
Commodity derivative instruments loss | (206,810) | (56,263) | ||||
306,342 | 172,127 | |||||
Expenses | ||||||
Operating | 83,244 | 51,162 | ||||
Transportation | 35,807 | 25,927 | ||||
Production taxes | 35,355 | 13,845 | ||||
General and administrative | 17,581 | 12,841 | ||||
Depletion, depreciation and accretion | 66,691 | 36,698 | ||||
Asset impairment | — | 3,420 | ||||
Interest | 6,055 | 5,633 | ||||
Foreign exchange (gain)/loss | 887 | (24) | ||||
Transaction costs and other expense/(income) | 12,697 | 3,619 | ||||
258,317 | 153,121 | |||||
Income/(Loss) before taxes | 48,025 | 19,006 | ||||
Current income tax expense | 5,000 | — | ||||
Deferred income tax expense/(recovery) | 9,782 | 8,657 | ||||
Net Income/(Loss) | $ | 33,243 | $ | 10,349 | ||
Other Comprehensive Income/(Loss) | ||||||
Unrealized gain/(loss) on foreign currency translation | (620) | (807) | ||||
Foreign exchange gain/(loss) on net investment hedge, net of tax | 5,375 | 5,714 | ||||
Total Comprehensive Income/(Loss) | $ | 37,998 | $ | 15,256 | ||
Net Income/(Loss) per share | ||||||
Basic | $ | 0.14 | $ | 0.04 | ||
Diluted | $ | 0.13 | $ | 0.04 |
Condensed Consolidated Statements of Cash Flows
Three months ended | ||||||
March 31, | ||||||
(US$ thousands) unaudited | 2022 | 2021 | ||||
Operating Activities | ||||||
Net income/(loss) | $ | 33,243 | $ | 10,349 | ||
Non-cash items add/(deduct): | ||||||
Depletion, depreciation and accretion | 66,691 | 36,698 | ||||
Asset impairment | — | 3,420 | ||||
Changes in fair value of derivative instruments | 133,332 | 40,358 | ||||
Deferred income tax expense/(recovery) | 9,782 | 8,657 | ||||
Foreign exchange (gain)/loss on debt and working capital | 1,171 | 157 | ||||
Share-based compensation and general and administrative | 4,660 | 802 | ||||
Other expense | 12,653 | — | ||||
Amortization of debt issuance costs | 353 | 57 | ||||
Translation of U.S. dollar cash held in parent company | 10 | 356 | ||||
Asset retirement obligation settlements | (8,795) | (5,625) | ||||
Changes in non-cash operating working capital | (57,108) | (66,567) | ||||
Cash flow from/(used in) operating activities | 195,992 | 28,662 | ||||
Financing Activities | ||||||
Proceeds from/(repayment of) bank credit facilities | (104,409) | 400,000 | ||||
Debt issuance costs | — | (2,834) | ||||
Proceeds from the issuance of shares | — | 98,339 | ||||
Purchase of common shares under Normal Course Issuer Bid | (37,207) | — | ||||
Share-based compensation – tax withholdings settled in cash | (11,567) | (3,551) | ||||
Dividends | (7,918) | (5,337) | ||||
Cash flow from/(used in) financing activities | (161,101) | 486,617 | ||||
Investing Activities | ||||||
Capital and office expenditures | (75,027) | (40,345) | ||||
Bruin acquisition | — | (418,241) | ||||
Property and land acquisitions | (1,941) | (2,471) | ||||
Property divestments | 6,581 | 4,010 | ||||
Cash flow from/(used in) investing activities | (70,387) | (457,047) | ||||
Effect of exchange rate changes on cash & cash equivalents | (3,121) | 2,289 | ||||
Change in cash and cash equivalents | (38,617) | 60,521 | ||||
Cash and cash equivalents, beginning of period | 61,348 | 89,945 | ||||
Cash and cash equivalents, end of period | $ | 22,731 | $ | 150,466 |